HomeMy WebLinkAbout2024-07-05
Electronic Council Communications Information
Package
Date:July 5, 2024
Time:12:00 PM
Location:ECCIP is an information package and not a meeting.
Description: An ECCIP is an electronic package containing correspondence received by Staff for
Council's information. This is not a meeting of Council or Committee.
Alternate Format: If this information is required in an alternate format, please contact the
Accessibility Coordinator, at 905-623-3379 ext. 2131.
Members of Council: In accordance with the Procedural By-law, please advise the Municipal Clerk
at clerks@clarington.net, if you would like to include one of these items on the next regular agenda
of the appropriate Standing Committee, along with the proposed resolution for disposition of the
matter. Items will be added to the agenda if the Municipal Clerk is advised by Wednesday at noon
the week prior to the appropriate meeting, otherwise the item will be included on the agenda for the
next regularly scheduled meeting of the applicable Committee.
Members of the Public: can speak to an ECCIP item as a delegation. If you would like to be a
delegation at a meeting, please visit the Clarington website.
Pages
1.Region of Durham Correspondence
1.1 Durham Region’s 2025 Strategic Plan Community Engagement
Summary - June 27, 2024
3
2.Durham Municipalities Correspondence
2.1 City of Pickering - Shared E-Scooter Pilot Program - July 3, 2024 90
3.Other Municipalities Correspondence
3.1 Township of Otonabee-South Monaghan - Regulations for the
Importation and Safe Use of Lithium-ion Batteries - June 28, 2024
105
4.Provincial / Federal Government and their Agency Correspondence
4.1 Ontario Ombudsman - 2023-2024 Annual Report - June 26, 2024
Link to 2023-2024 Annual Report
5.Miscellaneous Correspondence
5.1 AMO Advocacy on Homelessness Encampments - July 2, 2024 107
5.2 Enbridge Gas Inc. - 2023 Utility Earnings and Disposition of Deferral &
Variance AccountBalances Application and Evidence - Updated - July 2,
2024
108
July 5, 2024
Electronic Council Communications Information Package (ECCIP)
Page 2
THIS LETTER HAS BEEN FORWARDED TO THE EIGHT AREA CLERKS
The Regional Municipality of Durham
Corporate Services Department – Legislative Services Division
605 Rossland Rd. E.
Level 1 PO Box 623 Whitby, ON L1N 6A3
Canada
905-668-7711 1-800-372-1102
durham.ca
Alexander Harras M.P.A. Director of Legislative Services & Regional Clerk
Sent Via Email
June 27, 2024
June Gallagher
Clerk
Municipality of Clarington 40 Temperance Street Bowmanville, ON L1C 3A6
Dear June Gallagher:
RE: Durham Region’s 2025 Strategic Plan Community Engagement Summary (2024-COW-23), Our File: C13
Council of the Region of Durham, at its meeting held on June 26, 2024, adopted the following recommendations of the Committee of the Whole:
“A) That a copy of Report #2024-COW-23 of the Chief
Administrative Officer, be received for information;
B) That the following recommended next steps, as contained in Section 7 of Report #2024-COW-23, be endorsed:
i) If approved, Regional staff, in collaboration with the Strategic Plan Advisory Group and the consultant, will
complete further analysis to explore the data within the above mention themes and draft Durham Region’s 2025 Strategic Plan;
ii) The draft plan be presented back to the community for additional input in the Fall 2024 and then presented to
Regional Council for final review and endorsement in December 2024; and
C) That a copy of Report #2024-COW-23 be forwarded to the local area municipalities within the Region of Durham.”
If you require this information in an accessible format, please call 1-800-372-1102 ext. 2097.
Page 3
If you require this information in an accessible format, please call 1-800-372-1102 extension 2097.
Please find enclosed a copy of Report #2024-COW-23 for your
information.
Alexander Harras
Alexander Harras,
Director of Legislative Services & Regional Clerk
AH/ks
Enclosed
c: E. Baxter-Trahair, Chief Administrative Officer
Page 4
If this information is required in an accessible format, please contact 1-800-372-1102 ext. 2071
The Regional Municipality of Durham
Report
To: Committee of the Whole From: Chief Administrative Officer
Report: #2024-COW-23 Date: June 12, 2024
Subject:
Durham Region’s 2025 Strategic Plan Community Engagement Summary
Recommendations:
That the Committee of the Whole recommends to Regional Council:
A) That a copy of report #2024-COW-23 be received for information; and
B) That the recommended next steps in section 7 be endorsed; and
C) That a copy of this report be forwarded to the local area municipalities within the Region of Durham.
Report:
1. Purpose
1. The purpose of this report is to share a summary of the engagement phase activities and the preliminary themes identified that will support the development of
Durham Region’s 2025 Strategic Plan.
2. Background
2.1 Durham Region’s Strategic Plan is the guiding document that outlines how we deliver a sustainable future through leadership, collaboration, innovation and environmental stewardship.
2.2 The current Durham Region Strategic Plan is approaching its end in December
2024. Work is underway to develop Durham Region’s 2025 Strategic Plan.
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2.3 The Strategic Plan will guide the direction of our work over the next few years. It will outline how we will continue to deliver a sustainable future and act as a compass to advance our work to achieve the futures we want to create.
2.4 On September 27, 2023, Regional Council endorsed the process to develop Durham Region’s 2025 Strategic Plan and governance structure, as detailed in the Committee of the Whole report #2023-COW-32.
2.5 Durham Region’s 2025 Strategic Plan is being developed in five phases:
a. Phase 1: Knowledge Gathering (February – May 2023) – Complete
b. Phase 2: Planning (June – December 2023) – Complete
c. Phase 3: Engagement (January – June 2024) – Complete
d. Phase 4: Writing and Approvals (July – December 2024)
e. Phase 5: Implementation (January 2025 – Onward)
2.6
In January 2024, staff launched the engagement phase of the project. The first
engagement activity was a full-day planning session with Regional Council on January 25, 2024.
3. Previous Reports and Decisions
3.1 Committee of the Whole #2023-COW-32
3.2 Regional Council September 27, 2023
3.3 Special Regional Council Meeting January 25, 2024
4. Phase 3: Engagement – What We Did
4.1 As part of the process to develop Durham Region’s 2025 Strategic Plan, the project team developed an engagement plan outlining key partner, level of engagement, strategies and timelines. The objectives for the project’s engagement phase were:
a. To increase community awareness of the process to develop Durham Region’s 2025 Strategic Plan.
b. To ensure residents had the opportunity to have their say in the future of Durham Region.
c. To obtain input from the community on what they would like to see reflected in
Durham Region’s 2025 Strategic Plan.
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4.2 The public engagement portion of the Strategic Planning process was launched on March 1, 2024, with the goal of reaching and receiving feedback from as many residents across the region as possible.
4.3 Durham Region’s online engagement platform, Your Voice Durham was the primary engagement tool and featured project materials, an events calendar, the online survey and youth art contest.
4.4 Throughout the month of March, the team executed a variety of communications tactics to encourage the community to visit the website. A total of 25 posts were
shared to the Region’s three social media accounts (Facebook, X, and LinkedIn). There were 8,400 website visits in the month of March.
4.5 A total of 24 pop-up events were scheduled throughout the Region to support face-to-face engagement with residents, providing Regional staff with an opportunity to
speak with residents from each of the eight local area municipalities. Approximately
900 face-to-face interactions were generated through events. Comments gathered through these interactions were included in the qualitative data analysis.
4.6 A total of 13 presentations were delivered, reaching over 100 people. Delegations to all eight local area municipalities were completed between February 20 and March
25, 2024. Staff also presented to four Committees of Council and to the Durham
Economic Development Task Force to reach representatives from the business community.
4.7 A total of 700 flyers and 1,000 post-cards were distributed/posted in libraries, seniors centres, welcome centres, community, and recreation centres and handed
out to residents.
4.8 Elementary and secondary school students were encouraged to share their future vision for Durham Region by submitting their original visual or digital artwork through the website. The theme of the contest was “Designing Our Future.”
4.9 In addition, an internal engagement strategy was implemented to gather input from approximately 400 staff, including department heads, directors, managers and front-
line staff. Feedback was obtained from planning workshops with staff.
4.10 Engagement efforts resulted in approximately 1,400 in-person interactions; a total of 2,149 survey responses received and a total of 20 youth art contest submissions received.
4.11 The feedback received from the online survey and discussion with residents
informed four additional community conversations throughout the month of May with community partners, business representatives and youth. A total of 84 people attended the community conversations representing 47 organizations/groups. These community conversations were used to generate ideas to inform the Regional Strategic Plan.
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5. Preliminary Engagement Results – What We Heard
5.1 The following section contains a summary of the preliminary themes identified from community consultation data. They include data obtained from recent Regional
public consultation efforts, the Strategic Plan community survey, in-person interactions at community pop-up events, the youth art contest, internal engagement, and community conversations with partners, business leaders, and youth.
5.2 Based on a preliminary analysis of community consultation data, the following
defining characteristics of life in Durham Region were identified:
• Access to nature, including parks, trails, waterfronts and greenspace;
• Mix of rural and urban spaces;
• Sense of safety;
• Diverse and inclusive community; and
• Unique local industries, including agriculture, energy, and small businesses.
5.3 Based on a preliminary analysis of community consultation data, the data was clustered and grouped into the key issues for Durham Region. They are listed as follows:
• Cost of Living: Challenges were identified for the rise in cost of living, with a significant focus on housing and rental costs. Concerns were expressed about inadequate support for an increasing number of residents experiencing homelessness. Food insecurity was also identified as a growing issue. Affordability challenges for childcare, young people, and seniors were
commonly highlighted. Property taxes and the average living wage were identified as a contributors to affordability challenges in the region.
• Rapid Growth: A sense that Durham Region is growing at a rapid rate and that corresponding improvements in urban planning, infrastructure, and
services have not been able to keep up with the pace of change. Infrastructure, affordable housing, and service delivery including transit, have been challenged to meet growing needs. Concerns were raised around land use planning decisions that do not protect agricultural lands, natural habitats for wildlife and natural surroundings. Overall, a perceived inadequate response
to rapid growth is recognized as the primary issue affecting Durham Region.
• Infrastructure: Road maintenance and capacity was identified as lagging behind demand in the region. Traffic and road congestion was identified as an issue, with specific references to urban planning for housing developments
and density challenging the current transportation infrastructure. There was a
sense that housing is being built without thoughtful planning of services or
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access to green space, upgrading of infrastructure, or other amenities beyond homes, such as trails, bike lanes, and side walks. Access to high-speed internet services were identified as critical.
• Community Well-being: An observed increase in people experiencing homelessness and those living with mental health and addictions challenges in the community. In some cases, increased homelessness visible within community spaces caused uneasiness and concern.
• Safety: Concerns about safety for pedestrians in areas without sidewalks, general road safety, crime, and police services were expressed.
• Service Delivery: A sense that existing community services and resources,
including housing and health services are under strain associated with a growing and changing population. A growing need for health services to support an aging population was identified, including emergency response. Concerns were identified around value for money and responsible budgeting of tax dollars for corresponding improvements in core services. The need for
partnerships and collaboration was highlighted to support the coordination of service delivery. Perceived inequitable service delivery to northern parts of Durham was also identified as a challenge.
• Transit: Input focused on the need for reliable and affordable transit options to
address sustainability, cost of living, and mobility for students and seniors. Issues of service delivery to northern Durham were shared.
• Health Services: A need for more health services in the region was identified, including primary care providers, hospitals, and paramedic/emergency
services. Also identified was an increased need for services to support people living with mental health and addiction challenges, as well as a growing demographic of seniors.
• Leadership: Comments related to the lack of shared vision for the region.
Concerns were raised around responsible budgeting and decision-making to ensure investments align with community needs. The need for improved collaboration with all levels of government was highlighted. Lack of trust in government was identified as a theme.
• Community Connection: Lack of social cohesion and common identity, changing demographics, the need for representation, lack of public spaces to gather and build community were all cited as challenges. The loss of local media was also identified as a contributor to the lack of social cohesion. Social isolation and the lack of community engagement were also identified as
themes.
• Climate Change Impacts: Adverse impacts due to climate change and severe weather were identified for many areas of living in the region, including
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contributions to issues surrounding affordability, food security, and health. There was a sense that current development planning does not address climate challenges. Loss of agricultural land and climate impacts on agriculture
were also identified as concerns.
• Technology: Concerns regarding job loss due to automation and the shift in labour markets was expressed as a key concern. The need for cyber security due to increasing threats was raised. Social media was noted as an enabler to
the creation of bias, mistrust, and misinformation. It was noted that access to technology for civic engagement may not be possible for all segments of the population.
5.4 Based on a preliminary analysis of community consultation data, the data was clustered and grouped into the key aspirations for Durham Region. They are as
follows:
• Adapting to Growth: Desire to have a clear vision and proactive plans in place for careful growth, including infrastructure and waste management to support growth. Density was identified as a precursor to sustainable and
effective service delivery, particularly for transit system improvements however, maintaining greenspace in built-up environments was also identified as important to well-being. The need to adapt to meet the needs of the growing and changing population was also identified as a key theme, specifically regarding the delivery of the Region’s programs and services.
• Service Delivery: Desire for increased transparency and accountability, responsible budgeting, taking a proactive and preventative approach, working with all levels of government and partners in the community, effective core service delivery, and service innovation.
• Supports for Vulnerable Populations: Access to services for an aging population, children and youth, newcomers, refugees and asylum seekers, those who are experiencing homelessness, low-income residents, and those who are living with mental health and addiction issues.
• Environmental Protection and Sustainability: Improved access to nature, preservation of green spaces in neighbourhoods, preservation of agricultural lands, safeguarding of wildlife. Increased urban density to allow for efficient transit and service delivery. Thoughtful development, expanded transit
services, and clean energy are expected to support environmentally sustainable growth.
• Mobility Options: Desire for improved public transit to reduce car
dependency, active transportation, and walkable neighbourhoods with access
to nature and amenities.
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•Business and Employment: Attraction and retention of businesses and
employers who offer a variety of employment opportunities, especially for
youth. Increase in skilled workers, supports for local businesses tourism, and
newcomers are needed. Strengthening of current industry and diversification
and development of new industries was identified. Post-secondary institutions
were identified as opportunities for skills training for the future.
•Civic Engagement: Desire for more opportunities for the public to be heard by
leaders, to access information, and contribute to regional decision-making. A
desire for improved Indigenous relations and was also identified.
•Public Space: Welcoming and accessible public spaces to build community
and share in community arts, culture, and entertainment events locally that arefree of charge. Waterfront development to create beautiful natural publicspaces and thriving business spaces was identified.
•Recreation and Leisure: Local recreation opportunities, arts and cultural
events, community gatherings, and entertainment. In particular, the aspiration
for youth and senior recreation opportunities was identified. Also, the
awareness and communication of these opportunities was noted.
•Technology and Innovation: Opportunity to use new technologies andmethods to modernize regional practices, deliver efficient programs and
services, and enable community engagement.
5.5 For additional information, please refer to Attachment 1.
6.Relationship to Strategic Plan
6.1 This report supports the development of Durham Region’s 2025 Strategic Plan.
7.Next Steps
7.1 If approved, Regional staff, in collaboration with the Strategic Plan Advisory Group
and the consultant, will complete further analysis to explore the data within the
above mentioned themes and draft Durham Region’s 2025 Strategic Plan.
7.2 The draft plan will be presented back to the community for additional input in the Fall
2024 and then presented to Regional Council for final review and endorsement in
December 2024.
7.3 If endorsed, it is recommended that a copy of #2024-COW-23 be forwarded to the
local area municipalities within the Region of Durham.
7.4 For additional information, contact: Andrea Smith, Policy Advisor, Corporate Initiatives or Lesley-Ann Foulds, Manager, Corporate Initiatives.
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8. Conclusion
8.1 The Strategic Initiatives team would like to thank Regional Council, staff, partners, and residents who participated in the engagement activities. The feedback received
will be used to draft Durham Region’s 2025 Strategic Plan.
9. Attachments
Attachment #1: Community Survey Results (enclosed)
Attachment #2:
Community Survey (enclosed)
Attachment #3: Presentation
Prepared by: Andrea Smith, Policy Advisor, Corporate Initiatives, and Lesley-Ann Foulds, Manager, Corporate Initiatives.
Approved by: Sandra Austin, Executive Director, Strategic Initiatives.
Respectfully submitted,
Elaine C. Baxter-Trahair Chief Administrative Officer
Original Signed By
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Attachment #1 Community Survey Results
Part 1: Where are we now?
Question 1
Respondents were asked to rate statements below on a scale from 1 to 5, where 1 is
strongly disagree and 5 is strongly agree. The following table shows the percentage of respondents who agreed or strongly agreed with the statement.
Table 1. Ratings summary.
Statement Percentage of
Respondents who Agree or Strongly Agree
I plan to live in Durham Region over the next 5-10 years.
73%
I feel welcome wherever I go in Durham Region.58%
Durham Region delivers services well.52%
Durham Region supports those in need. 50%
The future feels positive and bright for Durham Region.47%
Durham Region is a safe place.41%
There is a sense of prosperity in Durham Region.40%
Durham Region has strong leadership.39%
Durham Region is ready for the future. 37%
Infrastructure in Durham Region is in excellent shape. 33%
Current public transit serves the public well. 32%
Durham Region is a leader in environmental sustainability. 32%
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Question 2
Respondents were asked to share any other statements they would use to describe Durham Region. From the written responses received (approximate total of 955), the
following overarching themes emerged:
• Growth and Infrastructure
• Leadership
• Affordability
• Safety
• Transit
Examples of qualitative feedback received from respondents include:
• “Fast growing but missing infrastructure to support the needs. This includes affordable housing, child care, addiction and mental health services... There needs
to be an effort made from all levels to help.”
• “Rapidly changing and growing, prompting a need to foster community cohesion amidst an increasingly diversifying population.”
• “I am a 28-year-old adult that has lived in Durham all my life and want to continue
to live here. Housing is very unaffordable in Durham Region and it makes me question if I can live here in the future. The only way I can live here now is by living with family. Please do more to address this and pressure the levels of government to do the same.”
• “Continues to have the charm of rural and the amenities and opportunities of urban. Hoping this rural/urban balance will be maintained and respected by limiting urban sprawl as much as possible.”
• “Increased population size will require more infrastructure for roads and affordable
housing. My desire for Durham Region is that there is affordable housing for all yet conservation and expansion of Durham Region's beautiful nature (parks, greenspace).”
• “I have lived in Durham Region since 1968 and have seen positive things happen.
Please continue to make adjustments in public transit so that I can continue to age with dignity.”
Question 3
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Respondents were asked to select up to five statements that best reflected how they feel about Durham Region. The table below shows the top responses.
Table 2. Summary of how respondents feel about Durham Region.
Statement Percentage of respondents
selected this statement
I am connected to nature in Durham Region. 48%
I feel safe in Durham Region. 40%
I am free to live the way I want in Durham Region. 36%
I am treated fairly in Durham Region. 34%
I can afford to live in Durham Region. 28%
Multi-generational living is possible in Durham Region. 26%
I live in a beautiful built environment. 25%
I have deep connections to my community in
Durham Region.
19%
None of these statements reflect how I feel
about Durham Region.
17%
My community has a lively, vibrant, and
creative buzz.
11%
This place has tremendous entrepreneurial
spirit and opportunity.
11%
My hard work and accomplishments are valued here. 11%
Other 3%
Question 4
From the written responses received (approximate total of 860), the following overarching themes emerged:
• Affordability
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• Access to Nature
• Community
• Leadership
• Safety
Examples of qualitative feedback received from respondents include:
• “I am deeply saddened by the number of homeless residents that I see and the seemingly lack of services and safe spaces for them.”
• “I’ve lived in Durham for 25+ years …I am very well connected to the community. Nature is reserved fairly well in Durham, lots of park areas, waterfront and conservation areas. I think there’s much for everyone in Durham.”
• “I feel my basic needs are met, but think this region has the opportunity to do things
differently and not really taking advantage of that opportunity.”
• “As a working professional, I'm starting to feel like I can't afford to live and work in Durham Region and have real concerns about where I will be in the next 5 years.”
• “As a senior and a renter, I have been priced out of Durham region and I worry about my future here. This is also a huge issue for new Canadians and refugees in this region.”
• “I generally feel safe except maybe when a lot of homeless people are gathered
together on the trails. House prices have skyrocketed so my adult children have little chance of affording a home. There are many warehouses being put up and hopefully that brings jobs to the region, but it would be nice if some of the abandoned warehouses were re-developed.”
• “There are few events during the year that let us come together as a community. Or they are not well advertised in way that the general public can find, i.e. outside of community newspapers.”
Part 2: Share your thoughts and ideas
Question 5
Respondents were asked to select up to five areas of opportunity they thought were the most exciting for Durham Region over the next 10 years. The table below shows the top
responses.
Table 3. Summary of areas of opportunity.
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Opportunity Percentage of respondents selected this opportunity
Public health services. 33%
Community safety. 32%
Affordable housing. 32%
New infrastructure. 29%
Quality of public space. 28%
Greener neighbourhoods. 27%
Public transit and mobility solutions. 27%
Responsible budgeting. 23%
Environmental sustainability and climate resilience. 21%
Clean energy production 20%
Businesses and investment. 19%
Post-secondary education. 18%
Income and housing supports. 17%
New technology. 17%
Social services. 16%
Skilled workers. 15%
Agriculture and agri-tourism. 14%
Public participation in governance and policy changes. 12%
Partnerships between public and private organizations. 8%
Other 4%
Question 6
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From the written responses received (approximate total of 710), the following overarching themes emerged:
• Access to Nature
• Sustainability and Environment
• Growth
• Affordability
• Leadership
• Safety
Examples of qualitative feedback received from respondents include:
• “Healthy and green are critical. Neighbourhood should promote active
transportation, walkability, and social connection for good mental health. Mental
health services should be way more accessible - particularly for kids where early intervention can prevent more serious issues. It’s ridiculous that we all have to drive everywhere all the time. Plan neighborhoods within walking distance of where we need to go. These are a complex problem, new technology (ai) can help
us get there.”
• “I think that the more the public gets involved in how we work and live, the better. I think civic engagement is the cornerstone of any thriving, connected community.
We have the opportunity to expand our meaning of public health and community
wellbeing and look at our collective health from a population and community perspective. We can be a leader in clean energy production and model green communities for other municipalities.”
• “Social and physical infrastructure are among the most important services the region can provide.”
• “I believe the Region needs a better response to issues that are becoming
increasingly evident: homelessness, mental health/addictions, opioid crisis. This response cannot be to ignore or swept under the carpet. There are agencies in the Region doing work in these areas. Work with and support them. The answers don't have to lie exclusively on the Region.”
• “We need to place more value on agricultural lands and reduce urban sprawl into prime farmlands in the north. We should be increasing medium and high-density housing in urban areas where there is existing infrastructure and public transit.”
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• “Durham Region is the last part of the GTA that still has the majority of its green
space and farmland undeveloped. It has a unique opportunity to build communities
while still protecting access to wildlife and nature in an unprecedented way for urban Ontario.”
• “As the region is poised to grow there is a tremendous opportunity to make bold
decisions that make this region liveable for all by investing in infrastructure, transit and community spaces. We need places where people can gather in person, not behind screens, and the ability for people to make a life here, not just commute somewhere else to work.”
• “I think Durham could be a better place to live, even a desirable place, but there needs to be a lot of work done to fight car dependency, and to have real public spaces where people feel like gathering and spending time. Housing is also a concern here, but I think that since there's a push to densify in Durham there's
opportunities to consider how to do that density in a more distributed model to make good third spaces in existing and new neighbourhoods.”
Part 3: The longer–term future
Question 7
Respondents were asked to imagine their life in Durham Region in 2035 and to select up to five areas that will have the biggest impact on them and their community. The table below shows the top responses.
Table 4. Summary of impact areas.
Areas Percentage of respondents selected this answer
Affordability. 50%
Community safety. 33%
Aging population. 33%
Public health issues. 32%
Aging infrastructure. 30%
Urbanization and density. 27%
Trust in government. 26%
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Mental health support needs. 26%
Severe climate change. 22%
Food insecurity. 20%
Immigration and newcomers. 20%
Safe and sustainable energy
solutions.
16%
Waste management. 13%
Refugees and asylum seekers. 13%
Diversity and inclusion. 13%
Artificial intelligence. 12%
Loss of local media. 11%
Economic competitiveness. 11%
Sense of unity, versus polarization. 11%
Global unrest. 11%
Sense of belonging. 10%
Global pandemics. 6%
Other 1%
Question 8
From the written responses received (approximate total of 620), the following overarching
themes emerged:
• Affordability
• Newcomers
• Growth
• Leadership
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• Health Services
Examples of qualitative feedback received from respondents include:
• “Life in Durham in 2035 is marked by diversity, inclusivity, improved public health, a strong sense of belonging, and enhanced trust in government. These positive developments contribute to a thriving and cohesive community, where residents are empowered to contribute to and benefit from the shared prosperity and well-
being of the region.”
• “In my community we are seeing a lot of newcomers which is contributing to diversity. There are opportunities to learn from other cultures which we rarely had before.”
• “Many more services are needed for our aging population and infrastructure. More Long-Term Care Homes and Senior Residences are desperately needed.”
• “There is already an aging population and aging infrastructure. i.e., roads, some
building water main, lack of schools in appropriate places. So these need to be addressed. Affordability will be important as million-dollar homes are definitely not in the budget for most people. Working towards better waste management - recycling better, less reliance on single use products and more sustainable energy sources.”
• “Durham Region is completely unaffordable, rent-wise, and I don't think the average salary for people who actually work in the region covers the cost of living here. We have a large aging population which are not leaving their homes because the quality of retirement housing is low and the style is not desirable, and
so we have a lot of underutilized housing. I also don't see partnerships with local First Nations, Inuit, Metis and urban Indigenous communities on this list but committing to all forms of Reconciliation, especially economic, has great opportunity to bring vibrancy, authenticity and justice to the Region.”
• “Durham seems to be changing rapidly with respect to the composition of the population and the challenges we face (i.e. cost of living, litter, economic development, etc.). I welcome change and especially the diverse population. But I am concerned that with diversity comes prejudice and polarization. I think the biggest thing will be to foster a community that cares for each other and is
empathetic to each other, regardless of our personal journeys. I also want to ensure the region is championing Reconciliation with Indigenous Peoples, and helping the community live harmoniously with the Indigenous people of this land."
Question 9
Respondents were asked which regional government services and programs they
thought would be most important to them and their community over the next 10 years. The table below shows the top responses.
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Table 5. Summary of services and programs.
Service or Program Percentage of respondents selected this answer
Roads and infrastructure programs. 37%
Public health programs. 36%
Long-term care and senior’s services. 36%
Police services. 30%
Housing and homelessness services. 30%
Transit services. 26%
Community safety and well-being programs. 25%
Regional planning for growth. 22%
Paramedic services. 22%
Waste management services. 18%
Climate change programs. 18%
Children’s services. 16%
Regional budget planning. 16%
Income support services. 15%
Family services. 14%
Agriculture and rural economic
development.
13%
Traffic safety programs. 11%
Access to information. 10%
Cycling infrastructure. 9%
Diversity, equity, and inclusion
programs.
9%
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Community engagement opportunities. 9%
Business services. 8%
Local arts and culture opportunities. 8%
Newcomer and immigrant support services. 7%
Tourism services. 5%
Other 1%
Question 10
From the written responses received (approximate total of 550), the following overarching
themes emerged:
• Aging Population
• Growth
• Health Services
• Transit
• Safety
Examples of qualitative feedback received from respondents include:
• “Most importantly, we need to boost services for our aging population. We do not
have enough long-term care and old age homes to support the next generation.
We need more supports available to them to combat issues such as loneliness and depression, along side a wide range of physical ailments.”
• “A dramatically improved transit system is essential for quality of life/equity,
offering mobility/affordable option to single vehicles, needed for economic prosperity of Region and reducing GHGs and air pollution.”
• “Durham health department provides consistently excellent service. So, for
influenza clinics, every Durham resident should be able to get immunized through the health department. For example, your COVID clinics were A+.”
• “Let's focus on keeping our population healthy so that we can ease the burden on
the health care system.”
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• “Safe and accessible transportation is essential for any growing region or
municipality, so these are quite important. Our communities are also heavily dependent on whether our most vulnerable are looked after, namely the homeless and low-income families.”
• “When planning for growth and inclusion community engagement is important. Need to include a diverse representation of views including from Indigenous Peoples, racialized people, aging population and people with disabilities. When developing new spaces ensure current spaces are maintained and available for all to feel included. Need to actively include views from the lived experiences of
people in marginalized groups who interact and live in the Region.”
Question 11
Respondents were asked to provide any additional comments about their vision for the future of Durham Region. From the written responses received (approximate total of 695), the following overarching themes emerged:
• Leadership
• Growth
• Affordability
• Community
• Safety
Examples of qualitative feedback received from respondents include:
• “We need safe neighborhoods and open spaces where we can be active without fear of harm.”
• “Durham must protect its waterways, its forests, and its green space as much as possible. The outdoor opportunities available in Durham are unique and must remain a vital part of Durham’s expansion and development plans. Durham must also greatly improve its transit and infrastructure if it really plans to welcome more residents. Otherwise it will only welcome more traffic, more gridlock, and
consequently more pollution and accidents.”
• “Align with the municipalities and get the job done.”
• “I think the future for Durham will be made or broken by how housing development
and population growth is managed. Community focused development will be
healthy, housing sprawl will not.”
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• “I think Durham has a good future IF it invests into mobility and better urban
planning. Safe, walkable, accessible neighbourhoods are the backbone of
community and inclusion. Keeping people from being displaced due to hardship and affordability issues, keeps populations invested in their own neighbourhoods. I'd like to see better transit from neighbourhood to neighbourhood, better bike infrastructure, more ability to walk to places for your daily needs. More local activities and better parks.”
Part 4 – Tell us about yourself
All questions in Part 4 were voluntary. The demographic questions were designed in collaboration with the Diversity, Equity, and Inclusion division of the Region of Durham. Participants were asked to provide demographic information. The following tables provide an overview of the survey respondent demographics.
Table 6. Demographics – Connection with Durham Region.
Connection with Durham Region Percentage of respondents selected this response *
I live in Durham Region. 85%
I work in Durham Region. 34%
I am a local business owner in Durham Region. 10%
I am a member of a community association and/or
volunteer in Durham Region.
16%
I am employed by the Regional Municipality of
Durham.
8%
I am employed by a local municipality. 2%
I prefer not to answer 3%
Other 3%
* Note: respondents were able to select more than one response to indicate their
connection to Durham Region.
Table 7. Demographics – Municipality.
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Municipality Percentage of respondents
Town of Ajax 15%
Township of Brock 3%
Municipality of Clarington 17%
City of Oshawa 26%
City of Pickering 12%
Township of Scugog 4%
Township of Uxbridge 3%
Town of Whitby 4%
Skipped 16%
Table 8. Demographics – Age Group.
Age Group Percentage of respondents
18 and under 1%
19 to 24 2%
25 to 34 18%
35 to 44 19%
45 to 54 14%
55 to 64 15%
65+ 16%
I prefer not to answer 3%
Skipped 12%
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Table 9. Demographics – Preferred language.
Preferred language Percentage of respondents
English 83.9%
French 0.7%
Both English and French 2.2%
Neither English nor French 0.2%
I prefer not to answer 1.0%
Skipped 12.0%
Table 10. Demographics – Immigration.
Born in Canada Percentage of respondents
Yes 64%
No 21%
I prefer not to answer 3%
Skipped 12%
Table 11. Demographics – Years in Canada.
Years lived in Canada Percentage of respondents
0-5 years 1.9%
6 to 10 years 2.6%
More than 10 years 15.7%
I prefer not to answer 0.2%
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Years lived in Canada Percentage of respondents
Skipped 79.6%
Table 12. Demographics – Indigenous identity.
Identify as an Indigenous person Percentage of respondents
Yes 4%
No 79%
I prefer not to answer 5%
Skipped 12%
Table 13. Demographics – Racial / ethnic identity.
Racial / Ethnic Identity Percentage of respondents
Asian - East 2.1%
Asian - South / East Indian / Indo-Caribbean 8.6%
Asian - Southeast 2.0%
Black / African 4.2%
North American Indigenous 0.9%
Non-White Latino or Hispanic
0.6%
Non-White Middle Eastern, West Asian, or North African 0.8%
Pacific Islander 0.2%
White - Caucasian 54.5%
Prefer to self-identify 0.9%
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Racial / Ethnic Identity Percentage of respondents
Mixed racial origin (i.e., with parents in multiple groups above,
regardless of place of birth)
2.3%
I prefer not to answer 10.9 %
Skipped 11.8 %
Table 14. Demographics – Gender and gender identity.
Gender / Gender Identity Percentage of respondents
Man 42.3%
Non-binary 0.4%
Two-Spirit 0.2%
Trans 0.3%
Woman 39.6%
Prefer to self-identify 0.3%
I prefer not to answer 6.0%
Skipped 10.9%
Table 15. Demographics – Identifying as a person with a disability.
Identify as a person with a disability Percentage of respondents
Yes 9%
No 74%
I prefer not to answer 5%
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Identify as a person with a disability Percentage of respondents
Skipped 12%
Table 16. Demographics – Education.
Completed Education Percentage of respondents
Less than High School diploma 1.0%
High School diploma 7.0%
Some College or University but no degree 14.1%
College Diploma 21.5%
Bachelor’s Degree 23.2%
Master’s Degree 11.8%
Professional Degree 4.4%
Doctorate 1.2%
I prefer not to answer 5.1%
Skipped 10.7%
Table 17. Demographics – Income.
Yearly Household Income Percentage of respondents
Less than $9,999 1.2%
$10,000 to $39,999 5.6%
$40,000 to $69,999 12.9%
$70,000 to $99,999 14.8%
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Yearly Household Income Percentage of respondents
$100,000 to $149,999 17.1%
$150,000 or more 22.6%
I prefer not to answer 24.2%
Skipped 1.6%
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Attachment #2: Community Survey
Developing Durham Region’s 2025 Strategic Plan
Survey Purpose
To help identify and prioritize the focus areas for the long-term vision and strategy for Durham Region.
Introduction
The current Durham Region Strategic Plan is approaching its end in December 2024.
Work is underway to develop Durham Region's 2025 Strategic Plan which will guide the direction of the Regional Municipality of Durham's work over the next few years. The Strategic Plan will outline how we will continue to deliver programs and services and advance our work to achieve the future we want to create.
We are excited to invite you to share your thoughts and ideas. Your voice matters and the
thoughts you share will be considered when creating the 2025 Strategic Plan.
The survey is designed to take approximately 5 to 10 minutes to complete. Your responses are anonymous.
For more information, please visit durham.ca/StratPlan2025 or email strategic.planning@durham.ca
Notice of Collection
Any personal information collected on this survey will be used to help develop the Region of Durham’s 2025 Strategic Plan. It is collected under the authority of the Municipal Act, 2001, and will be used in accordance with the Municipal Freedom of Information and Protection of Privacy Act (MFIPPA). Reports prepared by the Region on this survey will
not contain any personal information and will be subject to MFIPPA. For more information on the collection and use of your personal information, please contact the Corporate Privacy Officer at privacy@durham.ca or 905-668-7711 extension 2204.
Setting the Stage
The Region of Durham must work with all levels of government (federal, provincial, and
local) to achieve our goals. This table: "Who does what?" shows a broad overview of government areas of services and responsibilities. When developing Durham Region’s 2025 Strategic Plan, we must consider where we can take action and where we need to collaborate.
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Part 1: Where are we now?
When developing a strategic plan, it is important to understand where we are now as a
community before planning for the future.
Question 1
On a scale from 1 to 5, where 1 is strongly disagree and 5 is strongly agree, how
would you rate the following statements?
Choose 1 if you strongly disagree and 5 if you strongly agree.
Durham Region has strong leadership. Disagree 1 2 3 4 5 Agree
Durham Region delivers services well.Disagree 1 2 3 4 5 Agree
I feel welcome wherever I go in Durham Region.Disagree 1 2 3 4 5 Agree
Infrastructure in Durham Region is in excellent shape.Disagree 1 2 3 4 5 Agree
There is a sense of prosperity in Durham Region.Disagree 1 2 3 4 5 Agree
Current public transit serves the public well.Disagree 1 2 3 4 5 Agree
Durham Region is a safe place.Disagree 1 2 3 4 5 Agree
Durham Region is a leader in environmental sustainability.Disagree 1 2 3 4 5 Agree
Durham Region supports those in need.Disagree 1 2 3 4 5 Agree
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I plan to live in Durham Region over the next 5-10 years.Disagree 1 2 3 4 5 Agree
The future feels positive and bright for Durham Region Disagree 1 2 3 4 5 Agree
Durham Region is ready for the future.Disagree 1 2 3 4 5 Agree
Question 2
Please share any other statements you would use to describe Durham Region:
Question 3
Which five of these statements best reflect how you feel about Durham Region? Please select up to five statements.
☐ I feel safe in Durham Region.
☐ My hard work and accomplishments are valued here.
☐ I am treated fairly in Durham Region.
☐ I am connected to nature in Durham Region.
☐ I live in a beautiful built environment.
☐ I have deep connections to my community in Durham Region.
☐ Multi-generational living is possible in Durham Region.
☐ This place has tremendous entrepreneurial spirit and opportunity.
☐ My community has a lively, vibrant, and creative buzz.
☐ I am free to live the way I want in Durham Region.
☐ I can afford to live in Durham Region.
☐ None of these statements reflect how I feel about Durham Region.
☐ Other. Please specify:
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Question 4
Please share why you feel this way:
Part 2: Share your thoughts and ideas
Question 5
What opportunities do you think are the most exciting for Durham Region over the next 10 years? Please select up to five areas of opportunity.
☐ New technology. ☐ Skilled workers. ☐ Environmental sustainability
and climate resilience.
☐ Businesses and investment. ☐ Quality of public space. ☐ Public participation in
governance and policy changes.
☐ Post-secondary education. ☐ Public transit and mobility solutions. ☐ Clean energy production.
☐ Responsible budgeting. ☐ Affordable housing. ☐ Greener neighbourhoods.
☐ Public health services. ☐ New infrastructure. ☐ Income and housing
supports.
☐ Social services. ☐ Agriculture and agri-tourism. ☐ Community safety.
☐ Partnerships between public and private organizations.
☐ Other. Please specify:
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Question 6
Please share why you feel this way:
Part 3: The longer–term future
Question 7
We live in a time of significant change. Imagine your life in Durham Region in 2035. Which of the following do you think will have the biggest impact on you and your community? Please select up to five answers.
☐ Severe climate change. ☐ Community safety. ☐ Sense of belonging.
☐ Affordability. ☐ Food insecurity. ☐ Mental health support
needs.
☐ Aging population. ☐ Loss of local media. ☐ Aging infrastructure.
☐ Artificial intelligence. ☐ Global unrest. ☐ Immigration and
newcomers.
☐ Refugees and asylum
seekers.
☐ Safe and sustainable
energy solutions.
☐ Waste management.
☐ Urbanization and density. ☐ Global pandemics. ☐ Public health issues.
☐ Sense of unity, versus polarization. ☐ Economic competitiveness. ☐ Diversity and inclusion.
☐ Trust in government. ☐ Other (please specify):
Question 8
Please share why you feel this way:
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Question 9
Which regional government services and programs do you think will be most important to you and your community over the next 10 years? Please select up to 5 answers.
☐ Business services. ☐ Tourism services. ☐ Agriculture and rural economic development.
☐ Local arts and culture opportunities. ☐ Cycling infrastructure. ☐ Regional planning for growth.
☐ Community safety and
well-being programs.
☐ Diversity, equity, and
inclusion programs.
☐ Paramedic services.
☐ Public health programs. ☐ Regional budget
planning.
☐ Children’s services.
☐ Family services. ☐ Housing and homelessness services. ☐ Income support services.
☐ Long-term care and senior’s services. ☐ Transit services. ☐ Access to information.
☐ Police services. ☐ Newcomer and immigrant support services. ☐ Roads and infrastructure programs.
☐ Traffic safety programs. ☐ Waste management
services.
☐ Community
engagement opportunities.
☐ Other (please specify):
Question 10
Please share why you feel this way:
Question 11
Is there anything else you would like to share about your vision for the future of Durham Region?
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Part 4 – Tell us about yourself
The information you provide in the following questions helps us to understand the make-
up of the region which ensures the programs and services provided meet the needs of our changing population. Thank you in advance for providing this voluntary information.
Please tell us about your connection with Durham Region.
Select all that apply:
☐ I live in Durham Region.
☐ Town of Ajax
☐ Township of Brock
☐ Municipality of Clarington
☐ City of Oshawa
☐ City of Pickering
☐ Township of Scugog
☐ Township of Uxbridge
☐ Town of Whitby
☐ I work in Durham Region.
☐ I am a local business owner in Durham Region.
☐ I am a member of a community association and/or volunteer in Durham Region.
☐ I am employed by the Regional Municipality of Durham.
☐ I am employed by a local municipality.
☐ I prefer not to answer.
☐ Other (please specify)
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What age group do you belong to?
☐ 18 and under
☐ 19 to 24
☐ 25 to 34
☐ 35 to 44
☐ 45 to 54
☐ 55 to 64
☐ 65+
☐ I prefer not to answer.
Language
What language are you most comfortable communicating in?
☐ English
☐ French
☐ Both English and French
☐ Neither English nor French. Please specify:________
☐ I prefer not to answer.
Immigration
Were you born in Canada?
☐ Yes
☐ No
☐ I prefer not to answer.
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Immigration
If you were not born in Canada, how long have you lived in Canada?
☐ 0-5 years
☐ 6 to 10 years
☐ More than 10 years
☐ I prefer not to answer.
☐ Not applicable.
Indigenous identity
Do you identify as an Indigenous person (First Nation, Inuit or Métis)?
☐ Yes
☐ No
☐ I prefer not to answer.
Racial/Ethnic identity
Which of the following categories best describes your racial identity, regardless of your ethnicity and place of birth? Please choose one.
☐ Asian - East
☐ Asian - South / East Indian / Indo-Caribbean
☐ Asian - Southeast
☐ Black / African
☐ North American Indigenous
☐ Non-White Latino or Hispanic
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☐ Non-White Middle Eastern, West Asian, or North African
☐ Pacific Islander
☐ White
☐ Prefer to self-identify.
☐ I prefer not to answer.
☐ Mixed racial origin (i.e., with parents in multiple groups above, regardless of place
of birth). Please specify:
Gender/ Gender identity
Gender identity is a person’s internal and individual experience of gender. This may or may not correspond to one’s sex assigned at birth. What is your gender identity? Please chose all that apply.
☐ Man
☐ Non-binary
☐ Two-Spirit
☐ Trans
☐ Woman
☐ Prefer to self-identify:
☐ I prefer not to answer.
Disabilities
Do you identify as a person with a disability?
☐ Yes
☐ No
☐ I prefer not to answer.
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Education
What level of education have you completed?
☐ Less than High School diploma
☐ High School diploma
☐ Some College or University but no degree
☐ College diploma
☐ Bachelor’s degree
☐ Master’s degree
☐ Professional degree
☐ Doctorate
☐ I prefer not to answer
Socio-economic
What is your estimated household yearly income before taxes and deductions?
☐ Less than $9,999
☐ $10,000 to $39,999
☐ $40,000 to $69,999
☐ $70,000 to $99,999
☐ $100,000 to $149,999
☐ $150,000 or more
☐ I prefer not to answer.
Completion of survey
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Thank you for taking the time to complete the survey! Your feedback will be taken into consideration to develop Durham Region’s 2025 Strategic Plan.
Additional engagement opportunities will continue until June using the feedback gathered
from this survey. Please continue to check durham.ca/StratPlan2025 for updates.
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Durham Region’s 2025 Strategic Plan
Phase 3 – Engagement Summary Report
June 12, 2024
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Durham Region’s 2025 Strategic Plan Timeline
2Page 45
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Community Engagement Efforts
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Indigenous Governance and Organizations
•In October 2023, written letters providing notice for consultation were
delivered to the Williams Treaty First Nations.
o 1 follow-up engagement completed with the Mississaugas of Scugog
First Nation
•Regional staff continue to collaborate with Indigenous Governance and
organizations.
•Engagement through existing events and gatherings. Example, staff
attended the Ontario Health East -Central East Métis, Inuit, Indigenous
Peoples' Health Advisory Circle Meeting on March 22, 2024, to share
information. A total of 37 meaningful face-to-face interactions occurred.
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Council Planning Day
•Explored emerging issues
•Shared their vision of the
future
•Provided key input into the
development of the plan
•Results were used to inform
community survey and key
trends
5
Council Chambers – January 25, 2024
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Local Area Municipality Delegations
Select highlights from delegations:
•Enthusiasm and positive feedback on engagement
approach
•Desire for additional public pop-up events and
community engagement opportunities, specifically
evening sessions
•Commitment to promote the survey
6
City of Pickering’s Council
Chambers - March 4, 2024
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Public Engagement Activities
7Page 50
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Pop-Up Events
•24 pop-up events across the region
•Approximately 900 face-to-face interactions with residents
8
Oshawa –March 13, 2024 Durham College –April 5, 2024 Pickering –March 22, 2024
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Print Materials Distributed
•Flyers (N=700) and Post-cards (N=1,000) posted/distributed in:
o Libraries
o Seniors Centres
o Welcome Centres
o Recreation / Community Centres
9Page 52
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Your Durham March 2024
•8,400 website visits
•Over 2,100 survey
responses received
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Art Contest – Designing Our Future
•Young artists encouraged to share their vision for Durham Region
•20 submissions received
11Page 54
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Art Contest Submissions
12
~ Iyal -Age 5 ~ Jeremie -Age 8 ~ Christa -Age 10
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Art Contest Responses
•“Durham's future is full of parks and trees that kids can visit and make memories for a lifetime.”
•“Everyone recycling and no garbage on the ground. Lots of nature and farmland. More electric
cars.”
•“My future Durham region is pollution free with trees and clean lakes instead of deforestation and
factories that produce toxic gas.”
•“My future for Durham Region is a place where people from all ages and backgrounds can come
together to form a community. It is a place where there are opportunities for everyone to enjoy the
outdoors because we have done a good job of preserving nature and the environment around us.
My version of Durham is colourful and clean because people respect and take care of our public
spaces. We have many public buildings that serve a variety of purposes, like community centres,
libraries, schools, places of worship, hospitals and more. There are lots of parks where kids can play
and feel safe. Durham in ten years is a place where people want to live, work, play, learn and grow!”
•“Durham is a great place to live. My picture shows a park close to houses for kids to play and for
there to be peace.”
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Community Conversations
•May 2nd, 3rd, 6th and 14th
•3 hour in-person sessions focused on future scenario exploration
•A total of 84 of participants attended, representing 47
organizations/groups in Durham Region
•Sessions were designed for community partners, business
leaders, and youth leaders
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Community Conversations
15Page 58
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What We Heard from Community
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Respondent Demographics – Area Municipality
Q: Please tell us about your connection with Durham Region.
600
400
200
343 330
60
355
552
260
83 75 91
Skipped Town of Ajax Township of
Brock
Municipality
of Clarington
City of
Oshawa
City of
Pickering
Township of
Scugog
Township of
Uxbridge
Town of
Whitby
0
N=2,149
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Respondent Demographics – Age Group
Q: What age group do you belong to?
400
300
100
Skipped I prefer not
to answer
18 and under 19 to 24 25 to 34 35 to 44 45 to 54 55 to 64 65+
0
200
259
58
19 53
383 412
307 322 336
N=2,149
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Live 1830
Work
Local
Business Owner
Community Association
Member
RMD Staff
725
207
347
177
Prefer not to Answer59
Demographics from Community Survey
19
Q: Please tell us about your connection with Durham Region.
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Respondent Demographics – Immigration
Q: Were you born in Canada?
Yes
Skipped
No
446 (21%)
66 (3%)
262 (12%)
1375 (64%)
Prefer not to Answer
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Yes
Skipped
No
1708 (79%)
98 (5%)
266 (12%)
77 (4%)
Prefer not to Answer
21
Respondent Demographics – Indigenous Identity
Q: Do you identify as an Indigenous person (First Nation, Inuit or Métis)?
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Skipped
White
Prefer to self-identify
Prefer not to answer
Asian-East
Asian-S /E / IC
Black/African
North American Indigenous
Non-White Latino or Hispanic
22
Respondent Demographics – Racial/Ethnic Identity
Q: Which of the following categories best describes your racial identity, regardless of your
ethnicity and place of birth?
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Which five of these statements best reflect how you feel about Durham Region?
Please select up to five:
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What opportunities do you think are the most exciting
for Durham Region over the next 10 years?
Please select up to five areas of opportunity:
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Which of the following do you think will have the biggest impact on you and your community?
Please select up to five answers:
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Which regional government services and programs do you think will be most important to you and your community over the next 10 years?Please select up to five answers:
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Qualitative Results from Community Survey
27
Question Question Prompt # Qualitative
Responses
Q2 Please share any other statements you would use to describe Durham
Region.~ 950
Q4 Which five of these statements best reflect how you feel about Durham
Region? Please share why you feel this way.~ 800
Q6 What opportunities do you think are the most exciting for Durham
Region over the next 10 years? Please share why you feel this way.~ 700
Q8
We live in a time of significant change. Imagine your life in Durham
Region in 2035. Which of the following do you think will have the
biggest impact on you and your community? Please share why you feel
this way.
~ 600
Q10
Which regional government services and programs do you think will be
most important to you and your community over the next 10 years?
Please share why you feel this way.
~ 550
Q11 Is there anything else you would like to share about your vision for the
future of Durham Region?~ 700
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Internal Engagement Efforts
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Internal Engagement Activities
29
•Planning
Workshop (March
11)
•Online community
survey
Department
Heads
Directors
•Engagement
Workshop (March
21)
•Online community
survey
•Engagement
workshop (April
11 & 18)
•Online community
survey
Managers
All Staff
•Focus groups
(May)
•Online community
survey
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Department Head Planning Workshop
30
March 11, 2024
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Key Trends Affecting Durham Region
1 –Technology Advances
2 – Population Changes
3 – Severe Climate Change
4 – Health and Well-Being
5 – Electrification & Energy Transition
6 – Affordability
7 – Civic Engagement
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Director Planning Session
•March 21, 2024; 90-minute workshop
•Senior Leaders (Commissioners and Directors)
•Identified implications of key trends affecting Durham Region
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Manager Planning Session
•April 11 & 18, 2024; 90-minute workshops for managers
•Generated ideas to inform the Regional Strategic Plan
33Page 76
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Staff Conversations
•May 24-30, 2024: 90-minute in-person sessions
•5 workshops completed to gather insights on organizational
values and mission
34Page 77
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What We Heard from Staff
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What We Heard From Staff
Department Heads
•Provided key principles for
the design and scope of the
plan
•Provided input on plan
implementation
Senior Leadership Team
•Provided possible implications
of major trends affecting our
community, our organization,
and our programs and service
delivery
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What We Heard From Staff
Managers
•Provided key themes, ideas,
and strategies to respond to
major trends impacting the
region
Staff
•Provided ideas to inform
recommendations on Mission
and Values (how we work)
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Preliminary Findings –Summary of
What We Heard
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Summary of Defining
Characteristics
•Access to nature, including parks, trails, waterfronts and greenspace;
•Mix of rural and urban spaces;
•Sense of safety;
•Diverse and inclusive community; and
•Unique local industries, including agriculture, energy, and small businesses.
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Summary of What We Heard – Issues
Cost of Living
Rise in cost of living, with focus on
housing and rental costs. Increasing
number of residents experiencing
homelessness. Food insecurity growing.
Challenges for childcare, young people,
and seniors.
Rapid Growth
Urban planning, infrastructure, and
services to match pace of growth. In
particular, transportation infrastructure,
affordable housing, and service delivery
including transit. Protection of
agricultural lands and natural
surroundings.
Infrastructure
Traffic and road maintenance. Density
challenging the current transportation
infrastructure. Planning of services or
access to green space, upgrading of
infrastructure, or other amenities.
Access to high-speed internet services.
Community Well-being
Observed increase in people
experiencing homelessness and those
living with mental health and addictions
challenges in the community. In some
cases, increased homelessness visible
within community spaces caused
uneasiness and concern.
Safety
Concerns about safety for pedestrians
in areas without sidewalks, general
road safety, crime, and police services.
Service Delivery
Services and resources, including
housing and health services under
strain associated with a growing and
changing population. Services to
support an aging population. Value for
money and coordination of service
delivery. Service delivery to north
Durham.
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durham.ca 41
Summary of What We Heard – Issues cont’d
Transit
Reliable and affordable transit options
to address sustainability, cost of living,
and mobility for students and seniors.
Service delivery challenges to northern
Durham.
Health Services
Health services including primary care
providers, hospitals, and paramedic /
emergency services. Increased need for
services to support people living with
mental health and addiction challenges,
as well as a growing demographic of
seniors.
Leadership
Lack of shared vision for the region.
Responsible budgeting and decision-
making to ensure investments align
with community needs. Collaboration
with all levels of government. Lack of
trust in government.
Community Connection
Lack of social cohesion and common
identity, changing demographics,
representation, lack of public spaces to
gather and build community. The loss of
local media as contributors to a lack of
social cohesion. Social isolation and the
lack of community engagement.
Climate Change Impacts
Adverse impacts due to climate change
and severe weather including
contributions to issues such as
affordability, food security, and health.
Development planning to account for
climate challenges. Loss of agricultural
land and climate impacts on
agriculture.
Technology
Labour market impacts due to
automation. Cyber security challenges
due to increasing threats. Social media
as an enabler to the creation of bias,
mistrust, and misinformation.
Inequitable access to technology.
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durham.ca 42
Summary of What We Heard – Aspirations
Adapting to Growth
Clear vision and proactive plans in place
for careful growth and delivery of
services to meet needs of growing and
changing population. Density as a
precursor to sustainable and effective
service delivery. Greenspace identified
as important to well-being.
Service Delivery
Increased transparency and
accountability, responsible budgeting,
taking a proactive and preventative
approach, working with all levels of
government and partners in the
community, effective core service
delivery, and service innovation.
Supports for Vulnerable
Populations
Access to services for an aging
population, children and youth,
newcomers, refugees and asylum
seekers, those who are experiencing
homelessness, low-income residents,
and those who are living with mental
health and addiction issues.
Environmental Protection
and Sustainability
Access to nature, preservation of green
spaces in neighbourhoods, preservation
of agricultural lands, safeguarding of
wildlife. Thoughtful development,
expanded transit services, and clean
energy to support environmentally
sustainable growth.
Mobility Options
Improved public transit to reduce car
dependency, active transportation, and
walkable neighbourhoods with access
to nature and amenities.
Business and Employment
Attraction and retention of businesses
and employers, especially for youth.
Increase in skilled workers, supports for
local businesses tourism, and
newcomers. Strengthening of current
industry and diversification and
development of new industries. Post-
secondary institution contributions.
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durham.ca 43
Summary of What We Heard –Aspirations cont’d
Civic Engagement
More opportunities for the public to be
heard by leaders, to access information,
and contribute to regional decision-
making. Improved Indigenous relations.
Public Space
Welcoming and accessible public
spaces to build community and share in
community arts, culture, and
entertainment events locally that are
free of charge. Waterfront
development to create beautiful natural
public spaces and thriving businesses.
Recreation and Leisure
Local recreation opportunities, arts and
cultural events, community gatherings,
and entertainment, with emphasis on
youth and senior recreation
opportunities. Awareness and
communication of community
gatherings.
Technology and Innovation
Opportunity to use new technologies
and methods to modernize regional
practices, deliver efficient programs
and services, and enable community
engagement.
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durham.ca
Next Steps
•If approved, Regional staff, in collaboration with the Strategic
Plan Advisory Group and the consultant, will complete further
analysis to explore the data within the above mentioned themes
and draft Durham Region’s 2025 Strategic Plan
•The draft will be shared with Council and the community for
additional input in Fall 2024
•Final Council review and approval in December 2024
44Page 87
durham.ca
NEW
Revised Revised
Durham Region’s 2025 Strategic Plan Timeline
45Page 88
durham.ca
@RegionofDurham
Thank you!
Strategic Initiatives Division
Office of the CAO
strategic.planning@durham.ca
Page 89
Pickering Civic Complex | One The Esplanade | Pickering, Ontario L1V 6K7
T. 905.420.4611 | F. 905.420.9685 | Toll Free 1.866.683.2760 | clerks@pickering.ca | pickering.ca
Sent by Email
July 3, 2024
Alexander Harras Regional Clerk, Director of Legislative Services
The Regional Municipality of Durham 605 Rossland Road East Whitby, ON L1N 6A3
Subject: Director, Engineering Services, Report ENG 09-24 Shared E-Scooter Pilot Program
The Council of The Corporation of the City of Pickering considered the above matter at a Meeting
held on June 24, 2024 and adopted the following resolution:
A copy of Report ENG 09-24 is attached for your reference.
Should you require further information, please do not hesitate to contact the undersigned at
905.420.4660, extension 2019.
Yours truly,
Susan Cassel City Clerk
1. That Report ENG 09-24 regarding a Shared E-scooter Pilot Program be received;
2. That the staff be authorized to issue a ‘Request for Proposal’ to select a vendor to
undertake and implement a Shared E-Scooter Pilot Program in the City of Pickering;
3. That a copy of this report be circulated to the Region of Durham, Durham Regional Police
Service, Durham Region Transit, and all local Municipalities in Durham Region; and,
4. That the appropriate officials of the City of Pickering be authorized to take the necessary
actions as indicated in this report.
Corporate Services Department
Legislative Services
Page 90
Report ENG 09-24 July 3, 2024
Page 2 of 2
Encl.
SC:am
Copy: Durham Regional Police Services
Durham Region Transit
Jaclyn Grossi, Director of Legislative & Information Services, Town of Ajax June Gallagher, Municipal Clerk, Municipality of Clarington Chris Harris, Clerk, Town of Whitby Fernando Lamanna, Clerk, Township of Brock
Debbie Leroux, Clerk, Township of Uxbridge
Mary Medeiros, City Clerk, City of Oshawa Ralph Walton, Interim City Clerk, Township of Scugog
Chief Administrative Officer
Page 91
Report to Council
Report Number: ENG 09-24
Date: June 24, 2024
From: Richard Holborn
Director, Engineering Services
Subject: Shared E-Scooter Pilot Program - File: A-1440
Recommendation:
1. That Report ENG 09-24 regarding a Shared E-scooter Pilot Program be received;
2. That the staff be authorized to issue a ‘Request for Proposal’ to select a vendor to
undertake and implement a Shared E-Scooter Pilot Program in the City of Pickering;
3. That a copy of this report be circulated to the Region of Durham, Durham Regional Police
Service, Durham Region Transit, and all local Municipalities in Durham Region; and,
4. That the appropriate officials of the City of Pickering be authorized to take the necessary
actions as indicated in this report.
Executive Summary: The purpose of this report is to obtain Council’s authorization to
issue a Request for Proposal (RFP) to select a vendor to undertake and implement a shared e-scooter pilot program in the City of Pickering, and to provide Council with background information on shared e-scooter pilot programs.
The Ontario Ministry of Transportation (MTO) launched a five-year pilot program (Provincial Pilot Project – Electric Kick Scooters – ON Reg. 389/19) to run from January 1, 2020, to
November 27, 2024, to allow municipalities to choose where and how electric kick scooters (e-scooters) may be used. The MTO outlined that it is up to municipalities to pass by-laws to permit the use of e-scooters locally and determine where they can and cannot operate.
The Region of Durham (Region) passed By-law 23-2022 on April 27, 2022, permitting the use of e-scooters on Regional roads including Regional roads in the City of Pickering (City), but not
on roads under the jurisdiction of the City. To close this gap in connectivity for e-scooter users and have a consistent approach to e-scooters on all roads in Pickering, staff prepared the attached Electric Kick Scooter By-law No. 7992/23 (Attachment 1), which came into effect on February 27, 2023.
The City’s E-scooter By-law is consistent with the regulations implemented by the Region
including the restriction of the use of these devices anywhere other than roadways. The By-law
also provides enforcement authority to the Durham Regional Police Service.
To assess the potential impacts and uptake of a shared e-scooter pilot program in the City, staff are recommending that interested vendors be invited to participate in a pilot program through a competitive procurement process. Staff will develop terms of reference for the RFP
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Subject: Shared E-Scooter Pilot Program Page 2
for the pilot program after the authorization to do so is received from the Council. Subject to Council approval to issue an RFP, staff anticipate that a vendor(s) would be selected by the
end of 2024, and the program could commence in April 2025.
This program is supported by the Council approved City’s 2021 Integrated Transportation Master Plan, which has vision of “growing the adoption of active transportation, which generally is focused on walking (including the use of mobility aids) and cycling but can also include other transportation modes such as rollerblading, riding a skateboard, or a kick
scooter. Currently, cycling only represents 0.5% of all daily trips in Pickering, while walking
accounts for 9% of daily trips. Increasing active transportation and transit use by introducing micro-mobility and first and last mile solutions such as e-scooters will help to alleviate pressure on Pickering’s existing and future transportation network.” The shared e-scooter pilot program will advance the recommendations from the City’s Integrated Transportation Master Plan to
promote a safe, integrated and supportive transportation system and increase opportunities for
transit and active transportation.
Relationship to the Pickering Strategic Plan: The recommendations in this report respond
to the Pickering Strategic Plan Priority of Advance Innovation & Responsible Planning to Support a Connected, Well-Serviced Community.
Financial Implications: There are no financial implications at this time. Based on review of
other municipalities’ pilot programs, the capital and operating costs of the pilot project will be the responsibility of the vendors.
Further, a shared e-scooter program may require additional staffing resources, including for By-law and Operations.
Discussion: The purpose of this report is to obtain Council’s authorization to issue a Request for Proposal (RFP) to select a vendor to undertake and implement a shared e-
scooters pilot program in the City of Pickering, and to provide Council with background
information on shared e-scooter pilot programs.
The MTO launched a five-year pilot program (Provincial Pilot Project – Electric Kick Scooters – ON Reg. 389/19) to run from January 1, 2020, to November 27, 2024, to allow municipalities to choose where and how e-scooters may be used. The MTO outlined that it is up to
municipalities to pass by-laws to permit the use of e-scooters locally and determine where they
can and cannot operate. Municipalities are working on new regulations and programs to adapt to these new technologies.
The MTO e-scooter pilot program guidelines for municipalities stipulate that municipalities must inform MTO that they are participating in the pilot by contacting REO@ontario.ca. Furthermore,
it notes that the municipalities are required to monitor all collisions involving e-scooters on
roads within the municipality and provide semi-annual written reports to the ministry.
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MTO will use the information gathered from municipalities during the pilot to help determine if e-scooters will be allowed permanently in Ontario and if so, what the rules will be regarding
their operation.
Enacting an e-scooter pilot program will be contingent on the MTO extending the e-scooter pilot program. Should the MTO not extend the program, the City may not have the ability to participate in a shared e-scooter pilot program.
The RFP process would commence upon receiving approval from Council, and it is anticipated
that a vendor(s) would be selected by the end of 2024. Based on a review of neighbouring
municipality programs, the anticipated timeline for launching the shared e-scooter program in a typical year would be from the beginning of April to the end of October depending on weather conditions, commencing April 2025.
A. What defines Micro-mobility & E-Scooter
Micro-mobility refers to transportation over short distances provided by a range of small,
lightweight vehicles operating at speeds typically under 25 km/h and driven by users personally. These include e-scooters. They are ideal transportation options for providing the first and last mile connections to transit services at mobility hubs and could potentially help ease congestion near major transit hubs.
E-scooter is a vehicle that has:
x two wheels (one at the front and one at the back)
x a platform to stand on
x a handlebar for steering
x an electric motor that does not exceed 500 watts
x a maximum speed of 24km/h on a level surface
E-scooters are emerging across the world as an affordable and convenient micro-mobility option, particularly for people without access to a car, lack of sidewalks and those who do not live near transit stops or stations. E-scooters add another micro-mobility option to transportation road users for people who may not have the physical ability to use conventional
bikes and scooters. They have shown that they can improve multi-modality and gaps within
transit networks. There are people who may prefer using e-scooters instead of e-bikes because they take up less storage space and are easier to use regardless of balance skills.
There is growing research that shows mental and physical health and environmental benefits of micro-mobility. E-scooters are more likely to replace vehicular trips for short distances
because people can use them for longer distances and over challenging hills.
B. Shared and Privately-owned E-scooters
Privately owned e-scooters are vehicles that people purchase for their own use, and they are responsible for their charging, maintenance, and storage.
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Shared e-scooters are different from privately owned e-scooters. Shared e-scooters can be rented from a service provider for a fee per minute or per distance travelled. For example, at
the time of writing this report, the shared micro-mobility vendor Bird Canada indicate in their
mobile phone app a rate of $0.35/minute with a minimum of $2.50 fee for usage. The fees can change anytime as the pricing is at the vendor’s discretion. Such vehicles are typically unlocked using an app and the user must return them to a designated area or risk being charged a monetary penalty. The service providers are responsible for operating and
maintaining all their equipment, including the app needed to use the e-scooters.
C. Region of Durham E-scooter By-law
The Region’s and City’s ability to permit e-scooters depend on provincial and regional regulations, respectively. On April 27, 2022, the Region passed the Electric Kick Scooter By-Law 23-2022 permitting the use of e-scooters on Regional roads and consequently
e-scooters are now permitted on Regional roads in the City of Pickering.
D. City of Pickering E-Scooter By-law & Consultation Summary
Following the Region’s By-Law 23-2022 being passed, the City’s Corporate Services staff drafted the City’s E-Scooter By-law No. 7992/23, which came into effect in February 27, 2023 (Attachment 1). It includes the following:
x E-scooters are permitted on City streets but not on sidewalks, multi-use paths, parks, and trails.
x E-scooters are limited to roads with a speed limit of 60km/h and lower, unless within a
reserved bicycle lane.
x Operators must be 16 years of age or older.
x Operators under 18 years of age must wear a helmet.
x No cargo can be carried on an e-scooter.
x E-scooters must have a bell or horn and be equipped with a white or amber lamp at the front and red light at the rear.
A public consultation was undertaken by the City’s Corporate Services staff from May 21,
2021, to January 29, 2023 to gather public opinion on the City’s draft by-law. The total number of engaged participants that registered and contributed to the survey was 144. Only 31% of the 144 survey participants owned an e-scooter. The key takeaways from survey were as follows:
x 69% of the survey participants are in favour of the use of e-scooters on City roads
x 96% of the survey participants agree that e-scooters should be used in bicycle lanes
x 50% of the survey participants agree to prohibit use of e-scooters on sidewalks and pathways with 8% being undecided
x 52% of the survey participants disagree that e-scooters should be prohibited in parks and on trails with 7% being undecided
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x 62% of the survey participants are concerned with pedestrian safety
x 58% of the survey participants feel all riders should be required to wear helmets, not only riders 18 years and under
x 58% of the survey participants agree that a user must be at least 16 years of age to operate an e-scooter
Another notable finding from the survey feedback was that the participants who own and ride e-scooters regularly disagreed with prohibiting them on sidewalks and pathways due to not having adequate bicycle lanes on City roads.
E. Other Municipalities in the GTA
Since the commencement of the MTO’s five-year long e-scooter pilot program, various
municipalities such as the City of Brampton, City of Oshawa, and Town of Ajax, have opted in to participate in a pilot program to gather data on advantages and disadvantages of such programs and gauge local interest.
The City of Brampton’s pilot program in 2023 exceeded expectations with significant positive community feedback and interest which allowed the City to see the program return for another
year. They are using the services of a GTA-based micro-mobility company named Scooty.
The Town of Ajax partnered with Canadian company Bird Canada for its shared e-scooter pilot program for the month of October in 2023. In April 2024, the program commenced for a second time and is expected to be completed at the end of this year. The Town of Ajax has not placed any restrictions on the use of e-scooters on trails, multi-use paths, and within parks.
The City of Oshawa partnered with Canadian company Bird Canada and Singapore-based company Neuron Mobility to deliver a two-year ride-sharing pilot program at no cost to the City. The City of Oshawa’s webpage for their e-scooter pilot program notes that their ride-sharing vendors, Bird Canada and Neuron Mobility, have committed to responding to devices parked
incorrectly within 15 minutes to one hour. It also notes that for complaints pertaining to
privately owned e-scooters, residents can contact the City.
In 2021, City of Toronto Council voted unanimously to ban e-scooters on any City of Toronto roads. They are not allowed to be operated, left, stored, or parked on any public street in Toronto including bicycle lanes, cycle tracks, trails, paths, sidewalks, or parks over concerns
about safety related to e-scooters being ridden and littered on the sidewalk.
F. The Existing Technology
A micro-mobility share program is a service fully funded and operated by commercial businesses in which micro-mobility devices are made available to use for short-term rentals. Micro-mobility devices are generally rented and paid for through a mobile app. E-scooters can
also be privately owned and are commercially available for purchase along with a wide variety
of other unregulated micro-mobility devices.
Shared micro-mobility programs in Canada are regulated provincially and municipally with robust regulatory frameworks in place. Based on researching what other municipalities are
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Subject: Shared E-Scooter Pilot Program Page 6
doing, it is understood that the entire micro-mobility program, including all hardware (i.e. e-scooters), software and local program management, is typically provided for by the
micro-mobility company at no direct cost to the municipality.
A municipal shared micro-mobility program enables residents to simply download a free app onto their smartphone, locate a shared device, scan the QR Code located on the shared device via the smartphone app to unlock it, ride the shared device to their local destination where they would lock it via the app and park it in compliance with local municipal regulations,
ready for the next rider.
To date, regulated shared e-scooter programs are present in over 100 cities globally. In Canada, e-scooter share operations have existed in major cities across the country such as Calgary, Edmonton, Ottawa, and Windsor.
Municipal programs for shared e-scooters in cities such as Ottawa and Windsor have
regulations in place for shared e-scooter programs. For example, in Ottawa, Bird Canada has
a signed binding agreement with the City of Ottawa covering such items as:
x fees and securities
x parking of shared e-scooters
x removal of shared e-scooters
x COVID-19 related sanitation
x communication and education
x non-performance (of contractual obligations)
x data reporting to the City
x insurance
Depending on vendors’ products, some technology exists now that allows smart sidewalk protection which gives riders travelling on a sidewalk an audible alert and mobile notification
before the vehicle is brought safely and smoothly to a stop by reducing throttle (disengaging
the motor). It is known to be very uncomfortable riding these e-scooters without motor assistance.
Additionally, there are technologies that exist that will encourage users to stay and park within the geofenced green operational area, which can be found via an app. It’s the same app that is
used to make payments and rent shared e-scooters. Going outside this geofenced area will
result in the user’s e-scooter sounding an alarm and disabling the electric power. The user will need to manually push the e-scooter back into the geofenced area.
Geofencing technology uses GPS to create virtual boundaries around specific areas. E-scooter companies can use geofencing to restrict the speed or operation of e-scooters in certain
zones, such as pedestrian-only areas, parks, or high-traffic zones.
G. Insurance and Liability Concerns
One of the main concerns, other than the concerns of improper parking and placement of the e-scooters such as blocking sidewalks, impacts on the movement and safety of vulnerable sidewalk users such as disability groups, children, elderly population etc., is related to
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Subject: Shared E-Scooter Pilot Program Page 7
insurance and liability in the event of a collision, and property damage. As such, to reduce the probability of a collision taking place, staff recommend restricting the use of the shared
e-scooters in winter months. Therefore, in a typical year the program will likely run from April to
October, depending on weather conditions.
Many of the risks can be addressed through providing etiquette and education and requiring vendors to identify their risk mitigation measures during the RFP process. Bird Canada has a general rental and use of vehicle policy which includes terms and conditions related to risk and
responsibility.
It is worth reiterating that the risks associated with privately owned e-scooters are more challenging to mitigate compared to shared e-scooters, given the City has no control over adjustments people can make to their own e-scooters.
H. Advantages and Disadvantages
The decision to participate in a shared e-scooter program must consider the potential
advantages versus the disadvantages for both residents and the municipality. The table below outlines these considerations.
For Residents For Municipalities
Advantages x
x
Provides more transportation
options that can be appropriate for people with mobility or any other limitations.
Allows residents to take shorter
trips (last mile/first mile). For example - potential to use an e-scooter to get home from the GO station if people miss the
last DRT bus.
x
x
x
x
x
Contributes to meeting goals for
a multi-modal transportation system and greenhouse gas reductions.
Possibility to boost tourism and
increase exposure to local businesses.
Control over e-scooter’s speed.
Possible to have the vendor provide enforcement and education.
Potentially reduce auto
mode-share at congested areas within the City.
Disadvantages x
x
Potential conflicts with pedestrian path obstructions.
Risk of collision with
pedestrians, notably pedestrians
with disabilities if not trained properly (though the risks are not very different from conventional bikes).
x
x
Increased conflicts with pedestrians and increased risk of collision (though the risks are not very different from
conventional bikes).
Insurance products are not available for e-scooters.
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For Residents For Municipalities
x Littering (people may pick up x Increased demand for
and dispose of the e-scooters in maintenance of on-road and off-unauthorized areas). road bike facilities.
x Usage is contingent upon finding x Not feasible to enforce on trails
a vehicle nearby through the app given jurisdictional powers and
when one is needed immediately. resources to enforce speeds.
As noted earlier, the results from the municipal pilot programs will also inform the MTO’s decision on whether to permanently permit e-scooters in Ontario and regulations on how users operate e-scooters.
In summary, a shared e-scooter pilot program will allow staff to assess the performance and operation of a micro-mobility system under a test environment and gather data to support
recommendations for a permanent solution. It will support developing rules around their use in the City. It is an example of how the City can rethink the more conventional, auto-centric approach to transportation planning and infrastructure within the City. This program will also support the vision of growing an active transportation system, as identified in the City’s 2021 Integrated Transportation Master plan.
Attachment:
1. City of Pickering E-Scooter By-law No. 7992/23
Prepared By: Approved/Endorsed By:
Ridhita Ghose, P.Eng.
Transportation Engineer
Richard Holborn, P.Eng.
Director, Engineering Services
Nadeem Zahoor, P.Eng., M.Eng. Manager, Transportation & Traffic
Jason Litoborski
Manager, Municipal Law Enforcement 6HUYLFHV
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Cathy Bazinet
Manager, Procurement
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Recommended for the consideration
of Pickering City Council
Marisa Carpino, M.A. Chief Administrative Officer
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Page 100
The Corporation of the City of Pickering
By-law No.
Being a by-law to regulate the operation and use of electric
kick-scooters in the City of Pickering.
Whereas the Municipal Act, 2001, Highway Traffic Act and Ontario Regulation 389/19 allow municipalities to regulate the use of electric kick scooters,
And Whereas the Council of the City of Pickering desires to allow the operation of electric kick-scooters on municipal roadways;
And Whereas the Council of the City of Pickering desires to restrict the use of electric kick-scooters on certain municipal property.
Now therefore the Council of The Corporation of the City of Pickering hereby enacts as follows:
1. Short Title
1.1. This By-law may be referred to as the “E-Scooter By-law”.
2. Definitions
In this By-law:
2.1 “boulevard” means all parts of a highway including the sidewalk, but excluding the
roadway and shoulder.
2.2 “cargo” means goods carried on an electric kick-scooter by putting them on a platform, basket or container for carrying parcels or goods. Purses, backpacks or bags that are safely and securely attached to the operator are not considered cargo.
2.3 “Chief of Police” means the Chief of Police of the Durham Regional Police Service or an
authorized representative.
2.4 “City” means the geographic area of the City of Pickering or The Corporation of the City of Pickering, as the context requires.
2.5 “e-scooter” means an electric kick-scooter vehicle that has:
(a) two wheels placed along the same longitudinal axis, one placed at the front of
the kick-scooter and one at the rear,
(b) a platform for standing on between the two wheels,
(c) a steering handlebar that acts directly on the steerable wheel,
(d) an electric motor not exceeding 500 watts that provides a maximum speed of 24 kilometres per hour, and
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By-law No. /23 Page 2
(e) a maximum weight of 45 kilograms (kg) and wheels with a diameter of more than 430 millimetres.
2.5 “highway” has the same definition as in subsection 1 (1) of the HTA.
2.6 “HTA” means the Highway Traffic Act, R.S.O. 1990, c. H.8, as amended.
2.7 “multi-use pathway” means an in-boulevard path physically separated from motor vehicle traffic for use by cyclists, pedestrians and other non-motorized users.
2.8 “official sign” means a sign required by or erected on behalf of any federal, provincial, regional, or municipal government or agency thereof or board or commission or public
utility, including, but not limited to, signs designating hospitals, schools, libraries, community centres, arenas or other public government uses.
2.9 “pedestrian” means,
(a) a person on foot;
(b) a person in a wheelchair; or
(c) a child in a carriage, stroller or play vehicle.
2.10 “Region” or “Regional” means the municipal corporation of The Regional Municipality of Durham or the geographic area as the context requires.
2.11 “reserved bicycle lane” means those parts of the highway set aside for the use of
cyclists and designated by an official or authorized sign or by pavement markings.
2.12 “roadway” means that part of the highway that is improved, designed or ordinarily used for vehicular traffic, but does not include the shoulder, and, where a highway includes two or more separate roadways, the term “roadway” refers to any one roadway separately and not to all of the roadways collectively.
2.13 “shoulder” means that part of the highway immediately adjacent to the roadway and having a surface which has been improved for the use of vehicles with asphalt, concrete or gravel.
2.14 “sidewalk” means those parts of a boulevard set aside for the use of pedestrians.
2.15 “vehicle” includes a motor vehicle as defined in the HTA.
Application and Interpretation
3.1 This By-law applies to the City of Pickering.
Prohibition
4.1 No person shall operate, or cause to be operated, or use an e-scooter on a highway or any other property under the jurisdiction of the City unless:
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(a) permitted by and in accordance with the provisions of the HTA and Ontario Regulation 389/19, as amended;
(b) permitted by and in accordance with any applicable traffic by-laws; and
(c) permitted by and in accordance with the provisions of this By-law.
4.2 No person shall operate, or cause to be operated, or use an e-scooter on a highway with a legal speed limit greater than 60 kilometres per hour, unless within a reserved bicycle lane.
4.3 No person shall operate, or cause to be operated, or use an e-scooter where cycling,
skateboarding or rollerblading is prohibited.
4.4 No person shall operate, or cause to be operated any e-scooter on any sidewalk, trail, park or multi-use pathway under authority of the City.
General Regulations
5.1 No person under the age of 16 years shall operate an e-scooter.
5.2 No person under the age of 18 years old shall fail to wear a helmet that complies with the HTA when operating an e-scooter.
5.3 No person operating an e-scooter shall carry any other person thereon.
5.4 No person operating an e-scooter shall tow another person, vehicle or device.
5.5 No person operating an e-scooter shall attach himself or herself to another e-scooter,
vehicle or device for the purpose of being drawn or towed.
5.6 No person operating an e-scooter shall operate it in any position other than while standing at all times.
5.7 No cargo may be carried on an e-scooter.
5.8 No person shall park or stop an e-scooter or permit an e-scooter to remain parked or
stopped on a roadway, shoulder, boulevard or any other public property in Pickering unless authorized by the City of Pickering.
Safe Operation
6.1 The operator of an e-scooter shall keep a safe distance of at least one metre from
pedestrians and other users of the roadway or shoulder at all times and shall give way
to a pedestrian or bicycle by slowing or stopping where there is insufficient space for the pedestrian or bicycle and the e-scooter to pass.
6.2 Where reserved bicycle lanes are provided on a highway, an e-scooter shall only be operated in the reserved bicycle lane.
6.3 Where no reserved bicycle lanes exist on a highway where e-scooters are permitted to
operate, the operator of an e-scooter shall ride as close as practicable to the right-hand curb or edge of the roadway or on the paved shoulder.
Page 103
By-law No. /23 Page 4
6.4 No person shall operate an e-scooter within a crosswalk or pedestrian crossover, as defined in the HTA.
6.5 Every e-scooter shall be equipped with a bell or horn which shall be kept in good working order and sounded to notify cyclists, pedestrians or others of its approach.
6.6 When operated at any time from one-half hour before sunset to one-half hour after sunrise and at any other time when, due to insufficient light or unfavorable atmospheric conditions, persons and vehicles are not clearly discernible at a distance of 150 metres or less, every e-scooter shall carry a lighted lamp displaying a white or amber light at the front and a lighted lamp displaying a red light at the rear. The lamps may be
attached to the e-scooter or may be carried or worn by the operator on his or her person.
6.7 No person shall operate or use an e-scooter in such a manner that it may harm, injure or damage, either directly or indirectly, any person or property.
Enforcement
7.1 The provisions of this by-law may be enforced by a police officer pursuant to subsection 42(1)(h) of the Police Services Act, R.S.O. 1990, c. P.15.
Offences and Fines
8.1 Every person who contravenes any of the provisions of this By-law is guilty of an offence.
8.2 Every person who is convicted of an offence is liable to a fine as provided for in the
Provincial Offences Act, R.S.O. 1990, c. P.33, as amended.
Effective Date
9.1 , 2023 and shall be repealed on This By-law shall come into force on February WK
the earlier of:
(a) the revocation of Ontario Regulation 389/19: Pilot Project – Electric Kick Scooters; and
(b) November 27, 2024.
By-law passed this WK GD\RI)HEUXDU\
2ULJLQDO6LJQHG%\ ________________________________ Kevin Ashe, Mayor
2ULJLQDO6LJQHG%\ ________________________________ Susan Cassel, City Clerk
Page 104
The Corporation of the
Township of Otonabee-South Monaghan
Email: info@osmtownship.ca Telephone: 705.295.6852 Facsimile 705.295.6405
P.O. Box 70 20 Third St Keene, ON K0L 2G0
Visit our website at www.osmtownship.ca or follow us on Twitter @OSMTownship
June 28, 2024
Via Email: david.piccinico@pc.ola.org
Hon. David Piccini M.P.P.
Minister of Labour, Immigration, Training and Skills Development
117 Peter Street
Port Hope, ON
L1A 1C5
Dear Minister Piccini:
Re: Regulations for the Importation and Safe Use of Lithium-ion Batteries
I am writing today to bring to your attention a matter of significant importance to the
Township of Otonabee-South Monaghan, regarding the importation and safe use of
lithium-ion batteries.
At the June 17, 2024 Council Meeting the Fire Chief of the Township of Otonabee-South
Monaghan made a presentation to Council on the dangers presented by lithium-ion
batteries. The Fire Chief was reporting back from attending the Charged For Life
Symposium presented by the Office of the Fire Marshal.
During the presentation, the Fire Chief stressed that the increased importation and use
of non-Original Equipment Manufacturer (OEM) aftermarket batteries is presenting a
significant increase in fire and explosion, putting citizens and responding personnel in
danger. These after market batteries are not Underwriter Laboratories of Canada (ULC)
certified but can be imported into Canada without any associated regulations.
Unlicensed persons and locations can store and modify lithium-ion batteries in our
communities without regulations, providing dangerous conditions within a community.
Charging these batteries within the home or multi-unit dwellings can result in larger fires
with grave results.
Page 105
As Canada becomes more aware of Green Energy solutions, these batteries are used more
often, increasing the danger to our communities. We support the Ontario Fire Marshal’s
program to educate citizens on the danger associated with lithium-ion batteries and
encourage every municipality to actively promote safe practices for the use of lithium-ion
batteries.
We also call upon all levels of government to enact regulations for the importation, sale,
storage, and use of non-OEM or ULC certified lithium-ion batteries.
Thank you in advance for your attention to this very critical issue, and I look forward to
your prompt consideration and support.
Please do not hesitate to contact me or our Fire Chief if you require any additional
information.
Yours truly,
Township of Otonabee-South Monaghan
Joe Taylor, Mayor
Cc: MP, Philip Lawrence
All Ontario Municipalities
Page 106
From:ClerksExternalEmail
To:Chambers, Michelle
Subject:AMO Advocacy on Homelessness Encampments
Date:July 3, 2024 3:24:58 PM
AMO Advocacy on Homelessness Encampments
Dear Clerks and Heads of Council of Municipal Governments Across Ontario:
The AMO President and Board is requesting that this letter be shared with all
elected council members and administrative heads (i.e., CAO, City Manager)
in your municipality. Please post as an information item in your next council
meeting agenda.
On behalf of its municipal members, the Association of Municipalities of
Ontario (AMO) is urgently calling for provincial and federal leadership and
action to address the growing crisis of homelessness encampments in
communities across Ontario.
On July 2nd, AMO released a new policy paper Homeless Encampments in
Ontario: A Municipal Perspective detailing the state of this crisis and evidence-
based actions that must be taken.
Municipal governments are at the front lines of the homelessness crisis without
the resources or tools to support our residents and communities. We areasking the provincial and federal governments to work collaboratively witheach other and municipalities. These are complex issues that require
comprehensive responses from all orders of government working together.
For further resources and information, please visit www.amo.on.ca
Sincerely,
Colin Best
President, Association of Municipalities of Ontario (AMO)
Page 107
Richard Wathy Technical Manager Regulatory Applications Regulatory Affairs
tel 519-365-5376 Richard.Wathy@enbridge.com EGIRegulatoryProceedings@enbridge.com
Enbridge Gas Inc. P. O. Box 2001 50 Keil Drive North Chatham, ON N7M 5M1
July 2, 2024 VIA RESS AND EMAIL
Nancy Marconi Registrar Ontario Energy Board
2300 Yonge Street, 27th Floor Toronto, ON M4P 1E4 Dear Nancy Marconi:
Re: Enbridge Gas Inc. (Enbridge Gas) Ontario Energy Board (OEB) File No.: EB-2024-0125 2023 Utility Earnings and Disposition of Deferral & Variance Account
Balances Application and Evidence - Updated Further to the submission filed on May 31, 2024, enclosed please find the following updated exhibit:
Exhibit Updates
H-1-1 Enbridge Gas is filing the Integrated Resource Planning (IRP) Annual Report and IRP Technical Working Group Report In the event that you have any questions on the above or would like to discuss in more detail, please do not hesitate to contact me.
Sincerely,
Richard Wathy
Technical Manager, Regulatory Applications
cc.: D. Stevens (Aird & Berlis)
Page 108
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 1
Page 1 of 5
EXHIBIT LIST
A – Overview and Introduction
Exhibit Tab Schedule Contents
A 1 Exhibit List
2 Application
3
Overview and Approvals Required
B- Utility Results and Earning Sharing
Exhibit Tab Schedule Contents
B 1 2023 Earnings Sharing Amount and Determination
Process
1 Return on Rate Base & Equity and Earning Sharing
Determination
2 Utility Income
3 Utility Income Tax
4 Utility Rate Base and Continuity Schedules
5 Capital Structure and Cost of Capital
6 Reconciliation of Audited Income to Corporate
2 1 Delivery Revenue by Service , Rate Class and Service
Class
2 Customer Meters, Volumes and Revenues By Rate
Class
3 Revenue from Regulated Storage and Transportation of
Gas
4 Utility Other Revenue and Other Income
Page 109
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 1
Page 2 of 5
B- Utility Results and Earning Sharing
Exhibit Tab Schedule Contents
B 3 1 Operating and Maintenance Expense
Appendix A - Reconciliation Of Utility O&M Schedule
2022 & 2023 Results
2
Utility Capital Expenditure
3 Summary of Capital Cost Allowance
C- Enbridge Gas Inc Deferral and Variance Accounts
Exhibit Tab Schedule Contents
C 1 Enbridge Gas Inc. Deferral and Variance Accounts
1 1 Deferral and Variance Actual and Forecast Balances
2 Summary of Accounting Policy Changes Deferral
Account (APCDA)
3 Calculation of Bill C-97 Accelerated CCA Impact on Tax
Variance Deferral Account (TVDA)
D - EGD Rate Zone Deferral and Variance Accounts
Exhibit Tab Schedule Contents
D
1
Deferral & Variance Accounts Requested for Clearance
– EGD Rate Zone
Attachment 1 – Enbridge Gas Inc. Fugitive Emissions
Measurement Report
Attachment 2 – Fugitive Emmisions Measurement
Adminstration Deferral Account
1 1 Breakdown of the 2023 Storage and Transportation
Deferral Account
Page 110
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 1
Page 3 of 5
D - EGD Rate Zone Deferral and Variance Accounts
Exhibit Tab Schedule Contents
D 1 2 Breakdown of Transactional Services Revenue by Type
of Transaction
3 Breakdown of The 2023 Unaccounted-For Gas
Variance Account (2023 UAFVA)
4 Breakdown of the Average Use True-up Variance
Account
5 Storage RFP Letter
6 Storage RFP Summary (Redacted)
E – Union Rate Zones Deferral and Variance Accounts
Exhibit Tab Schedule Contents
E 1 Deferral & Variance Accounts Requested for Clearance
– Union Rate Zones
1 Breakdown of Upstream Transportation Optimization
Deferral Account
2 Breakdown of Short Term Storage Deferral Account
Appendix A – 2023 Storage Space and Deliverability
3 Summary of Non-Utility Storage Balances
4 Allocation of Short Term Peak Storage Revenues
between Utility/Non-Utility
5 Calculation of Balances by Rate Class in the NAC
Deferral Account
6 Calculation of Allocation of Short Term Transportation
Revenues to the Lobo D / Bright C / Dawn H
Compressor Project Cost Deferral Account
Page 111
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 1
Page 4 of 5
F – Rate Allocation
Exhibit Tab Schedule Contents
F 1 Allocation and Disposition of 2023 Deferral and
Variance Account Balances
1 1 Split of EGI Account Balances to Rate Zones
2 1 EGD - Unit Rate and Type of Service
2 EGD - Balances to be Cleared
3 EGD - Classification and Allocation of Deferral and
Variance Account Balances
4 EGD - Allocation by Type of Service
5 EGD - Unit Rate by Type of Service
6 EGD - Bill Adjustment for Typical Customers
3 1
Union – Unit Rate and Type of Service
2 Union – 2023 Deferral Account Balances to be Cleared
3 Union – Classification and Allocation of Deferral
Variance Account Balances
4 Union - Unit Rates for One-Time Adjustment - Delivery
5 Union - Bill Adjustment for Typical Customer
G – OEB Scorecard
Exhibit Tab Schedule Contents
G 1 2023 Scorecard Results
1 1 OEB Scorecard 2019 - 2023
Page 112
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 1
Page 5 of 5
H –Reports
Exhibit Tab Schedule Contents
H 1 1 IRP Annual Report and IRP Technical Working Group
Report
2 Indigenous Working Group Report
Page 113
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 2
Page 1 of 5
ONTARIO ENERGY BOARD
IN THE MATTER OF the Ontario Energy Board Act,
1998, S.O. 1998, c.15 (Schedule B);
AND IN THE MATTER OF an Application by Enbridge
Gas Inc. for an order or orders clearing certain
commodity and non-commodity related deferral or
variance accounts.
APPLICATION
1. Enbridge Gas Distribution Inc. (referred to in the evidence as EGD, Enbridge Gas or
the Company) and Union Gas Limited (referred to in the evidence as Union or the
Company) (together the Utilities) were Ontario corporations incorporated under the
laws of the Province of Ontario carrying on the business of selling, distributing,
transmitting and storing natural gas within the meaning assigned in the Ontario
Energy Board Act, 1998 (the Act). In the August 30, 2018 EB-2017-0306/0307
Decision and Order (the MAADs Decision), the Ontario Energy Board (OEB)
approved the amalgamation of the Utilities, as well as a five-year deferred rebasing
term during which a price cap rate-setting model would apply.
2. Effective January 1, 2019 the Utilities amalgamated to become Enbridge Gas Inc.
(Enbridge Gas). Following amalgamation, Enbridge Gas has maintained the existing
rates zones of EGD and Union (the EGD, Union North West, Union North East and
Union South rate zones).1 Enbridge Gas has also maintained most of the existing
deferral and variance accounts for each Rate Zone.
1 Collectively the Union North West, Union North East and Union South rates zones are referred to as
“Union rate zones”. Union North West and Union North East are collectively referred to as “Union North”.
Page 114
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 2
Page 2 of 5
3. Enbridge Gas, the Applicant, hereby applies to the OEB, pursuant to Section 36 of
the Ontario Energy Board Act, 1998, for an Order or Orders approving the clearance
or disposition of amounts recorded in certain deferral or variance accounts.
1. Earnings Sharing
4. In the MAADs Decision, the OEB approved, among other things, an asymmetrical
earnings sharing mechanism (ESM) during the deferred rebasing period, where
each year any earnings in excess of 150 basis points over the OEB-approved return
on equity (ROE) would be shared 50/50 between the Utilities and ratepayers.
5. In 2023, Enbridge Gas’s actual utility earnings did not exceed the OEB-approved
ROE by more than 150 basis points. Accordingly, no ESM amount is proposed to be
shared with ratepayers.
2. Enbridge Gas Inc.
6. The OEB has approved several deferral and variance accounts that relate to
Enbridge Gas as a whole (and not to specific Rate Zone(s)). These accounts are
listed at Exhibit C, Tab 1, Schedule 1. As 2023 is the last year of the deferred
rebasing term, Enbridge Gas seeks approval to clear the final balances of certain
Enbridge Gas deferral and variance accounts for 2023 as set out at Exhibit C, Tab 1,
Schedule 1.
3. EGD Rate Zone
7. As approved in the MAADs Decision and the 2019 Rates Case (EB-2018-0305),
Enbridge Gas maintained substantially the same deferral and variance accounts for
the EGD rate zone as during its 2014-2018 Custom IR term.
8. Enbridge Gas seeks approval to clear the final balances of certain EGD rate zone
deferral and variance accounts for 2023 as set out at Exhibit C, Tab 1, Schedule 1.
Page 115
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 2
Page 3 of 5
4. Union Rate Zones
9. As approved in the MAADs Decision and the 2019 Rates Case (EB-2018-0305),
Enbridge Gas maintained substantially the same deferral and variance accounts for
the Union Rate Zones as during its 2014-2018 IR term.
10. Enbridge Gas seeks approval to clear the final balances of certain Union rate zones
deferral and variance accounts for 2023 as set out at Exhibit C, Tab 1, Schedule 1.
5. Relief Requested
11. Enbridge Gas therefore applies to the OEB for such final, interim or other orders as
may be necessary or appropriate for the clearance or disposition of the 2023 deferral
and variance accounts requested in Exhibit C, Tab 1, Schedule 1. This includes final
disposition of certain accounts previously cleared on an interim basis. The proposed
manner of disposition is described at Exhibit F. Enbridge Gas proposes to clear the
balances in these accounts with the first available QRAM application following the
OEB’s approval, as early as January 1, 2025.
12. In conjunction with Enbridge Gas’s proposed Fugitive Emissions Investigation Plan
described at Exhibit D, Enbridge Gas requests approval of the new Fugitive
Emissions Measurement Administration Deferral Account at Exhibit D, Attachment 2.
13. Enbridge Gas requests that certain information included at Exhibit D, Tab 1,
Schedule 6 be treated as confidential under the OEB’s Practice Direction on
Confidential Filings. Equivalent information has been treated as confidential in prior
deferral and variance account clearance proceedings.
14. Enbridge Gas requests that this proceeding be heard in writing.
15. Enbridge Gas further applies to the OEB pursuant to the provisions in the Act and
the OEB’s Rules of Practice and Procedure for such final, interim or other Orders
and directions as may be appropriate in relation to the Application and the proper
conduct of this proceeding.
Page 116
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 2
Page 4 of 5
16. This Application is supported by written evidence. This evidence may be amended
from time to time as required by the OEB, or as circumstances may require.
17. The persons affected by this application are the customers resident or located in the
municipalities, police villages and First Nations reserves served by Enbridge Gas,
together with those to whom Enbridge Gas sells gas, or on whose behalf Enbridge
Gas distributes, transmits or stores gas. It is impractical to set out in this application
the names and addresses of such persons because they are too numerous.
18. Enbridge Gas requests that a copy of every document filed with the OEB in this
proceeding be served on the Applicant and Applicant’s counsel, as follows:
The Applicant:
Mr. Richard Wathy
Technical Manager, Regulatory Applications
Enbridge Gas Inc.
Address for personal service Enbridge Gas Inc.
P. O. Box 2001
50 Keil Drive North
Chatham, ON N7M 5M1
Telephone: 519-365-5376
Fax: 519-436-4641
Email: Richard.Wathy@enbridge.com
EGIRegulatoryproceedings@enbridge.com
- and –
Page 117
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 2
Page 5 of 5
The Applicant’s counsel:
Mr. David Stevens
Aird & Berlis LLP
Address for personal service Brookfield Place, P.O. Box 754
and mailing address: Suite 1800, 181 Bay Street
Toronto, Ontario M5J 2T9
Telephone: 416-863-1500
Fax: 416-863-1515
Email: dstevens@airdberlis.com
DATED: May 31, 2024, at Chatham, Ontario
ENBRIDGE GAS INC.
__________________________
Richard Wathy
Technical Manager, Regulatory
Applications
Page 118
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 3
Plus Appendix
Page 1 of 3
2023 DEFERRAL ACCOUNT DISPOSITION AND EARNINGS SHARING
OVERVIEW AND APPROVALS REQUESTED
1. Enbridge Gas Inc. (Enbridge Gas) is applying to the Ontario Energy Board (OEB)
pursuant to section 36 of the OEB Act for approval to dispose and recover certain
2023 deferral and variance account final balances for Enbridge Gas, and the
Enbridge Gas Distribution (EGD) and Union Gas (Union)1 rate zones. Enbridge Gas
is also presenting the 2023 earnings sharing mechanism (ESM) calculations for the
amalgamated utility.
2. The evidence in this Application is organized as follows:
Exhibit A: Overview and Introduction
Exhibit B: 2023 Utility Results and Earnings Sharing Amount
Exhibit C: Enbridge Gas Inc. Deferral and Variance Accounts
Exhibit D: EGD Rate Zone Deferral and Variance Accounts
Exhibit E: Union Rate Zones Deferral and Variance Accounts
Exhibit F: Rate Allocation
Exhibit G: OEB Scorecard
Exhibit H: Reports
3. Enbridge Gas proposes that the impacts which result from the disposition of 2023
deferral and variance account balances be implemented with the first available
QRAM application following the OEB’s approval, as early as January 1, 2025, to align
with other rate changes implemented through the Quarterly Rate Adjustment
Mechanism (QRAM).
1. Relief requested
4. Enbridge Gas seeks approval to clear the final balances of certain Enbridge Gas,
EGD rate zone, and Union rate zones 2023 deferral and variance accounts. The
balances of the 2023 deferral and variance accounts are set out at Exhibit C, Tab 1,
1 “Union rate zones” collectively refers to Union North West, Union North East and Union South.
Page 119
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 3
Plus Appendix
Page 2 of 3
Schedule 1. For ease of reference, a copy of Exhibit C, Tab 1, Schedule 1 is attached
at Appendix A to this exhibit.
5. Explanations for the balances in each account are set out at Exhibit C (Enbridge
Gas), Exhibit D (EGD rate zone) and Exhibit E (Union rate zones). The evidence also
indicates which accounts Enbridge Gas does not seek to clear in this proceeding.
The proposed clearance methodology for the accounts being cleared is set out at
Exhibit F.
6. In the MAADs Decision (EB-2017-0306/0307), the OEB approved, among other
things, an asymmetrical earnings sharing mechanism (ESM) during the 2019-2023
deferred rebasing period, where each year any earnings in excess of 150 basis
points over the OEB-approved return on equity (ROE) would be shared 50/50
between Enbridge Gas and ratepayers.
7. Enbridge Gas’s actual 2023 utility earnings did not exceed the OEB-approved ROE
by more than 150 basis points. Accordingly, no ESM amount is proposed to be
shared with ratepayers.
2. Disposition of deferral and variance accounts
8. Integration of the legacy billing systems for EGD and Union Gas enables Enbridge
Gas to dispose of balances in the 2023 deferral and variance accounts as a one-time
adjustment for all customers. Enbridge Gas proposes to dispose of the 2023 deferral
and variance accounts as a one-time adjustment for all general service, in-franchise
contract and ex-franchise rate classes.
9. The proposed approach to the one-time adjustment is consistent between the EGD
and Union rate zones and, subject to OEB approval as to timing, will be disposed of
as part of the January 2025 bills that customers receive in February 2025.
Page 120
Filed: 2024-05-31
EB-2024-0125
Exhibit A
Tab 3
Plus Appendix
Page 3 of 3
3. 2021 and 2022 UFG-related Deferral and Variance Accounts final disposition
10. As part of both the 2021 (EB-2022-0110) and 2022 (EB-2023-0092) OEB-approved
Deferral and Variance Account settlement agreements, UFG-related accounts were
disposed of on an interim basis, as Enbridge Gas committed to providing additional
information. Commitments made in the EB-2022-0110 settlement agreement with
regards to UFG-related deferral and variance accounts were addressed in evidence
filed in EB-2023-0092. In its submission on the EB-2023-0092 settlement
agreement, OEB staff noted they were satisfied with Enbridge Gas’s provision of this
information in accordance with its commitments in the OEB-approved 2021 Deferral
and Variance Account settlement proposal.
11. Included in this application, in Exhibit D, is the additional information Enbridge Gas
has committed to filing as part of the EB-2023-0092 settlement agreement with
regards to UFG-related deferral and variance accounts.
12. Having met the commitments of the 2021 and 2022 OEB-approved Deferral and
Variance Account settlement agreements, Enbridge Gas requests that the prior
interim dispositions of the 2021 and 2022 UFG-related deferral and variance
accounts be declared final.
4. Deferral and Variance Account request
13. In the EB-2022-0200 OEB-approved settlement agreement (Phase 1, Rebasing
Application), Enbridge Gas committed to providing a robust investigation plan related
to fugitive emissions for consideration and determination in the 2023 deferral and
variance account proceeding. Enbridge Gas has provided a robust Fugitive
Emissions Investigation Plan, within Exhibit D. Assuming that Enbridge Gas will
move forward with implementation of the Fugitive Emissions Investigation Plan,
Enbridge Gas requests OEB approval to establish the Fugitive Emissions
Measurement Administration Deferral Account to capture incremental costs incurred.
The draft deferral account has been provided at Exhibit D, Attachment 2.
Page 121
Filed: 2023-06-14
EB-2023-0092
Exhibit A
Tab 3
Appendix A
Page 1 of 1
Col. 1 Col. 2 Col. 3 Col.4
Line Account Reference to
No. Account Description Acronym Principal Interest Total Evidence
($000's) ($000's) ($000's)
EGD Rate Zone Commodity Related Accounts
1. Storage and Transportation D/A 2023 S&TDA 18,705.8 1,572.8 20,278.6 D-1, Page 1
2. Transactional Services D/A 2023 TSDA (41,738.1) (2,291.5) (44,029.6) D-1, Page 2
3. Unaccounted for Gas V/A 2023 UAFVA (6,922.7) (266.5) (7,189.2) D-1, Page 5
4. Total Commodity Related Accounts (29,955.0) (985.2) (30,940.2)
EGD Rate Zone Non Commodity Related Accounts
5. Average Use True-Up V/A 2023 AUTUVA 14,307.1 785.5 15,092.6 D-1, Page 69
6. Gas Distribution Access Rule Impact D/A 2023 GDARIDA - - - D-1, Page 79
7. Deferred Rebate Account 2023 DRA 2,132.7 187.1 2,319.8 D-1, Page 71
8. Transition Impact of Accounting Changes D/A 2023 TIACDA - - - D-1, Page 79
9. Electric Program Earnings Sharing D/A 2023 EPESDA - - - D-1, Page 79
10. Open Bill Revenue V/A 2023 OBRVA - - - D-1, Page 79
11. Ex-Franchise Third Party Billing Services D/A 2023 EFTPBSDA - - - D-1, Page 79
12. OEB Cost Assessment V/A 2023 OEBCAVA 3,732.8 302.1 4,034.9 D-1, Page 72
13. Dawn Access Costs D/A 2023 DACDA - - - D-1, Page 79
14. Incremental Capital Module D/A - EGD 2020-2023 ICMDA (4,909.0) (232.4) (5,141.4) D-1, Page 75
15. RNG Injection Service V/A 2022-2023 RNGISVA (331.5) (28.7) (360.2) D-1, Page 77
16. Pension and OPEB Forecast Accrual vs. Actual Cash Payment Differential V/A 2023 P&OPEBFAVACPDVA - - - D-1, Page 79
17. Total EGD Rate Zone (for clearance) (15,022.9) 28.4 (14,994.5)
Union Rate Zones Gas Supply Accounts OEB Account Number
18. Upstream Transportation Optimization 179-131 2023 8,087.2 444.0 8,531.2 E-1, Page 6
19. Spot Gas Variance Account 179-107 2023 - - - E-1, Page 55
20. Unabsorbed Demand Costs Variance Account 179-108 2023 41.5 37.8 79.3 E-1, Page 1
21. Base Service North T-Service TransCanada Capacity 179-153 2023 79.0 5.6 84.6 E-1, Page 45
22. Total Gas Supply Accounts 8,207.7 487.4 8,695.1
Union Rate Zones Storage Accounts
23. Short-Term Storage and Other Balancing Services 179-70 2023 1,637.5 89.9 1,727.4 E-1, Page 8
Union Rate Zones Other Accounts
24. Normalized Average Consumption 179-133 2023 (3,650.8) (201.3) (3,852.1) E-1, Page 4
25. Deferral Clearing Variance Account 179-132 2023 3,372.3 184.5 3,556.8 E-1, Page 19
26. OEB Cost Assessment Variance Account 179-151 2023 1,630.3 131.1 1,761.4 E-1, Page 42
27. Unbundled Services Unauthorized Storage Overrun 179-103 2023 - - - E-1, Page 55
28. Gas Distribution Access Rule Costs 179-112 2023 - - - E-1, Page 55
29. Conservation Demand Management 179-123 2023 - - - E-1, Page 55
30. Parkway West Project Costs 179-136 2023 (696.4) (48.7) (745.1) E-1, Page 20
31. Brantford-Kirkwall/Parkway D Project Costs 179-137 2022 (3.1) (0.3) (3.4) E-1, Page 23
32. Lobo C Compressor/Hamilton-Milton Pipeline Project Costs 179-142 2023 267.8 10.3 278.1 E-1, Page 33
33. Lobo D/Bright C/Dawn H Compressor Project Costs 179-144 2023 66.0 (39.5) 26.5 E-1, Page 37
34. Burlington-Oakville Project Costs 179-149 2023 (43.3) (3.1) (46.4) E-1, Page 40
35. Panhandle Reinforcement Project Costs 179-156 2023 (1,884.1) (145.9) (2,030.0) E-1, Page 46
36. Sudbury Replacement Project 179-162 2023 - - - E-1, Page 55
37. Parkway Obligation Rate Variance 179-138 2023 - - - E-1, Page 55
38. Unauthorized Overrun Non-Compliance Account 179-143 2023 (45.5) (4.3) (49.8) E-1, Page 36
39. Incremental Capital Module D/A - UGL 179-159 2019-2023 (383.7) (504.0) (887.7) E-1, Page 52
40. Pension and OPEB Forecast Accrual vs. Actual Cash Payment Differential V/A 179-157 2023 - (6,207.7) (6,207.7) E-1, Page 49
41. Unaccounted for Gas Volume Variance Account 179-135 2023 - - - E-1, Page 25
42. Unaccounted for Gas Price Variance Account 179-141 2023 (629.1) (132.3) (761.4) E-1, Page 30
43. Total Other Accounts (1,999.6) (6,961.2) (8,960.8)
44. Total Union Rate Zones (for clearance) 7,845.6 (6,383.9) 1,461.7
EGI Accounts
45. Earnings Sharing D/A 179-382 2023 - - - C-1, Page 1
46. Tax Variance - Accelerated CCA - EGI 179-383 2023 (28,483.3) (2,715.0) (31,198.3) C-1, Page 11
47. IRP Operating Costs Deferral Account 179-385 2023 3,081.2 247.3 3,328.5 C-1, Page 14
48. IRP Capital Costs Deferral Account 179-386 2023 - - - C-1, Page 22
49. Green Button Initiative D/A 179-387 2023 - - - C-1, Page 1
50. Cloud Computing Implementation Costs D/A 179-332 2023 - - - C-1, Page 1
51. Getting Ontario Connected V/A 179-324 2023 31,902.6 1,736.2 33,638.8 C-1, Page 23
52. Expansion of Natural Gas Distribution Systems V/A 179-380 2023 - - - C-1, Page 1
53. Accounting Policy Changes D/A - Other - EGI 179-381 2019-2023 5,511.3 36.2 5,547.5 C-1, Page 2
54. Impacts Arising from the COVID-19 Emergency D/A - EGI 179-384 2020-2021 - - - C-1, Page 1
55. Total EGI Accounts (for clearance)12,011.8 (695.3) 11,316.5
56. Total Deferral and Variance Accounts (for clearance)4,834.5 (7,050.9) (2,216.4)
Forecast for clearance at
January 1, 2025
Actual & Forecast Balances
Deferral & Variance AccountEnbridge Gas
Page 122
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Page 1 of 5
2023 ENBRIDGE GAS INC. EARNINGS SHARING AMOUNT
AND DETERMINATION PROCESS
1. For the year ended December 31, 2023, Enbridge Gas Inc. (Enbridge Gas, or the
Company) is not in an earnings sharing position, as its achieved return on rate base
and return on equity are below the threshold required for sharing. The earnings
sharing calculation is shown at Exhibit B, Tab 1, Schedule 1, while supporting
schedules that show the calculation of utility rate base, utility income and taxes, and
the utility capital structure components, are contained in the balance of the B
Exhibits. Exhibit B, Tab 1, Schedule 6 sets out a reconciliation of audited income to
corporate income.
2. The earnings sharing amount was determined in accordance with the following
prescribed methodology as identified within the EB-2017-0306/0307 OEB Decision
and Order, dated August 30, 2018, at pages 28 and 29, and within the
EB-2017-0306 pre-filed evidence at Exhibit B, Tab 1, pages 42 and 43:
if in any calendar year during the deferred rebasing term, Enbridge Gas’s
actual utility ROE is more than 150 basis points above the OEB-approved
ROE for that year (updated annually by the OEB), then the resultant amount
shall be shared equally (i.e., 50/50) between Enbridge Gas and its
ratepayers;
for the purposes of the earnings sharing mechanism (ESM), Enbridge Gas
shall calculate its earnings using generally accepted accounting principles
(GAAP) consistent with its external reporting, including the regulatory rules
prescribed by the OEB from time to time;
all revenues and costs that would otherwise be included in a cost of service
application shall be included in the earnings sharing calculation.
Page 123
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Page 2 of 5
3. While the threshold or benchmark for Enbridge Gas’s earnings sharing has changed
from that of each legacy utility1, the general process followed for calculating earnings
sharing amounts is consistent with each utility’s prior incentive regulation terms.
4. As articulated above, within Exhibit B, Tab 1, Schedule 1, the Company has
calculated earnings for sharing in two ways for confirmation purposes.
5. In part A), a return on rate base method is shown, while in part B), a return on equity
from a deemed equity embedded within rate base perspective is shown. Column 2
within the exhibit provides references indicating where additional evidence in support
of the determination of the amounts in the calculation can be found. Column 3
contains results shown in millions of dollars, or percentages.
1. Part A)
6. The level of utility income, $795.2 million (Line 4) divided by the level of utility rate
base, $15,858.9 million (Line 5) generates a utility return on rate base of 5.014%
(Line 6).
7. When compared to the Company’s required rate of return for ESM determination, of
6.637% (Line 7), as determined within the capital structure required in support of the
determined rate base amount (inclusive of the 150 basis point deadband on ROE
before earnings sharing is triggered), there is a resulting deficiency of 1.623%
(Line 8) on total rate base.
8. As shown in Lines 9 through 11, the deficiency of 1.623% multiplied by the rate base
of $15,858.9 million, produces a net under earnings or deficiency of $257.4 million,
which from a pre-tax perspective ($257.4 million divided by the reciprocal, 73.5%, of
the corporate tax rate which is 26.5%), results in a $350.2 million gross amount of
under earnings, and therefore nothing to be shared equally between ratepayers and
the Company. Column 2 provides supporting evidence references.
1 Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union).
Page 124
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Page 3 of 5
2. Part B) (Confirming the Calculated Earnings Sharing)
9. Net utility income applicable to common equity is first determined.
10. The $834.6 million (Line 14) of utility income before income tax, less utility taxes of
$39.4 million (Line 19), produces the $795.2 million of utility income used in part A)
above (at Line 4).
11. In order to determine utility net income applicable to a deemed common equity
percentage within rate base, all long term debt, short term debt and preference
share costs must also be reduced against the part A) $795.2 million utility income.
12. These reductions are shown at Lines 15, 16 and 17 which, along with the utility
income tax reduction already mentioned and shown at Line 19, results in a net
income applicable to common equity of $362.7 million, shown at Line 20.
13. The $362.7 million, divided by the deemed common equity level of $5,709.2 million
(Line 21, calculated as 36% of the $15,858.9 million rate base) produces a return on
equity of 6.352% (Line 23). When comparing the 6.352% achieved return on equity
to the threshold ROE percentage of 10.860% (Line 22), which is the OEB-approved
formula return on equity for 2023 of 9.360% plus the 150 basis point deadband
before sharing, there is a deficiency in ROE of 4.508% (Line 24).
14. The 4.508% multiplied by the common equity level of $5,709.2 million (Line 21)
produces a net under earnings or deficiency of $257.4 million, which from a pre-tax
perspective ($257.4 million divided by the reciprocal, 73.5%, of the corporate tax
rate), results in a $350.2 million gross amount of under earnings, and therefore
nothing to be shared equally between ratepayers and the Company. Column 2
provides supporting evidence references.
Page 125
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Page 4 of 5
3. Process Description
15. The calculation of utility earnings and any earnings sharing requirement starts with
financial results contained within the Enbridge Gas corporate trial balance. The
Company notes that the corporate trial balance includes the elimination of
transactions between each of the rate zones. This predominantly relates to the
elimination of regulated and unregulated storage and transmission revenues that
would have been reflected in the Union rate zones, offset by a corresponding
elimination of gas costs that would have been reflected for the EGD rate zone. This
reflects the fact that from a corporate perspective, EGD rate zone delivery revenues
are contributing to the costs of Union rate zones regulated and unregulated storage
and transmission services.
16. From there, in order to calculate the utility rate base, income, and capital structure
results, and supporting evidence exhibits, various adjustments, regroupings or
eliminations are required. This is accomplished by following and applying regulatory
rules as prescribed by the OEB and the standards associated with cost of service
rate related accounting processes. Examples are:
determination of rate base amounts using the average of monthly averages
value concept,
elimination of corporate interest expense due to the treatment of interest
expense as embedded in the capital structure balanced to rate base; and,
elimination of corporate income taxes due to the determination of income
taxes specific to utility results.
17. In addition, Enbridge Gas has made the appropriate adjustments in relation to non-
standard legacy EGD and Union rate regulated items which the OEB has either
decided in the past or are required in order to determine an appropriate utility return
on equity. Examples are:
rate base disallowance from EBRO 473 and 479 Decisions (Mississauga
Southern Link project amounts);
Page 126
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Page 5 of 5
exclusion of non-utility or unregulated activities;
elimination of approved shareholder incentives (such as Demand Side
Management incentives, amounts related to Transactional Services, short-
term storage, and net optimization incentives, and amounts related to Open
Bill program incentives); and
elimination of Central Functions Corporate Cost Allocation Methodology
(CFCAM) charges that did not pass the 3-prong test.
Page 127
Col. 1 Col. 2 Col. 3
Line
No.Description Reference Actual
1 Part A) Return on Rate Base & Revenue (Deficiency) / Sufficiency
($Millions) & (%'s)
2 Utility Income before Income Tax (Ex. B, Tab 1, Sch. 2)834.6
3 Less: Income Taxes (Ex. B, Tab 1, Sch. 3)39.4
4 Utility Income 795.2
5 Utility Rate Base (Ex. B, Tab 1, Sch. 4)15,858.9
6 Indicated Return on Rate Base % (line 4 / line 5)5.014%
7 Less: Required Rate of Return %(Ex. B, Tab 1, Sch. 5)6.637%
8 (Deficiency) / Sufficiency %-1.623%
9 Net Earnings (Deficiency) / Sufficiency (line 5 x line 8)(257.4)
10 Provision for Income Taxes (92.8)
11 Gross Earnings (Deficiency) / Sufficiency (line 9 / 73.5%)(350.2)
12 50% Earnings sharing to ratepayers (if line 11 > 1, line 11 x 50%) -
13 Part B) Return on Equity & Revenue (Deficiency) / Sufficiency
14 Utility Income before Income Tax (Ex. B, Tab 1, Sch. 2)834.6
15 Less: Long Term Debt Costs (Ex. B, Tab 1, Sch. 5)399.7
16 Less: Short Term Debt Costs (Ex. B, Tab 1, Sch. 5)32.9
17 Less: Cost of Preferred Capital (Ex. B, Tab 1, Sch. 5)0.0
18 Net Income before Income Taxes 402.1
19 Less: Income Taxes (Ex. B, Tab 1, Sch. 3)39.4
20 Net Income Applicable to Common Equity (line 18 - line 19)362.7
21 Common Equity (Ex. B, Tab 1, Sch. 5)5,709.2
22 Approved ROE (including deadband before earning sharing) % (Board-approved + 150bp)10.860%
23 Achieved Rate of Return on Equity % (line 20 / line 21)6.352%
24 Resulting (Deficiency) / Sufficiency in Return on Equity %-4.508%
25 Net Earnings (Deficiency) / Sufficiency (line 21 x line 24)(257.4)
26 Provision for Income Taxes (92.8)
27 Gross Earnings (Deficiency) / Sufficiency (line 25 / 73.5%)(350.2)
28 50% Earnings sharing to ratepayers (if line 27 > 1, line 27 x 50%) -
For the Year Ended on December 31, 2023
Summary
Return on Rate Base & Equity & Earnings Sharing Determination
Enbridge Gas Inc.
Ontario Utility
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 1 Page 1 of 1
Page 128
Col. 1 Col. 2 Col. 3 Col. 4
Unregulated Utility
Corporate Operations Adjustments Income
Line
No.Reference (a)(b)(c)(d) = (a)-(b)+(c)
($Millions)
1 Gas sales and distribution (Ex. B, Tab 2, Sch. 2)5,398.3 - (32.6) (i)5,365.7
2 Transportation (Ex. B, Tab 2, Sch. 3)140.4 (0.4) (0.8) (ii)140.0
3 Storage (Ex. B, Tab 2, Sch. 3)215.2 208.3 (0.3) (iii)6.5
4 Other operating revenue (Ex. B, Tab 2, Sch. 4)76.6 3.6 (15.2) (iv)57.8
5 Other income (Ex. B, Tab 2, Sch. 4)11.1 1.4 (2.6) (viii)7.1
6 Total operating revenue 5,841.6 212.8 (51.5) 5,577.1
7 Gas costs 2,873.4 70.7 (15.3) (i)2,787.4
8 Operation and maintenance (Ex. B, Tab 3, Sch. 1)1,303.2 24.1 (170.3) (v)1,108.8
9 Depreciation and amortization expense 756.6 19.5 (22.5) (vi)714.6
10 Fixed financing costs 4.0 - 2.8 (vii)6.8
11 Municipal and other taxes 126.3 1.5 - 124.8
12 Cost of service 5,063.5 115.8 (205.2) 4,742.5
13 Utility income before income taxes 834.6
14 Income tax expense (Ex. B, Tab 1, Sch. 3)39.4
15 Utility income 795.2
Notes on Adjustments:
(i) Reclassification of Union rate zone optimization revenue as a cost of gas reduction (15.3)
Elimination of the UGL rate zone unregulated storage cost from EGD rate zone revenues (17.3)
(32.6)
(ii)(0.8)
(iii) Elimination of the Union rate zone shareholder portion of net short-term storage revenue (before tax)(0.3)
(iv)(4.2)
Elimination of EGD rate zone Open Bill shareholder incentive 0.4
Elimination of EGD rate zone shareholder portion of transactional service revenues (5.7)
Elimination of demand-side management incentive (5.0)
Elimination of EGD rate zone net revenue from ABC T-service, considered to be non-utility (0.8)
(15.2)
(v) Elimination of donations (2.6)
Elimination of Central Functions Corporate Allocation Methodology (CFCAM) charges (11.2)
Elimination of non-utility costs to support the EGD ABC T-Service program (0.3)
Elimination of pension impairment charge (Phase 1 Decision EB-2022-0200)(156.1)
(170.3)
(vi) Eliminate amortization of PPD (purchase price discrepancy)(22.5)
Eliminate depreciation on disallowed Mississauga Southern Link amounts (EBRO 473 & 479)(0.0)
(22.5)
(vii)
2.8
(viii) Elimination of interest income from investments not included in utility rate base (0.7)
Elimination of interest income from affiliates (1.8)
-
(2.6)
EGI Utility Income
2023 Actual
Elimination of the Union rate zone shareholder portion of net optimization activity (before tax)
Interest on security deposits held during the year and included in elimination of corporate interest exp. Expense incurred to reduce bad
debt. The average amount of the security deposit held during the year is applied as a reduction to the allowance for working capital in rate
base
Elimination of the revenue indemnification received from Enbridge Inc. related to a non-utility Corporate tax planning Part VI.1 tax transfer
to EGI
Adjust EGD rate zone OBA costs to reflect EB-2013-0099 approved unit costs agreed to be used for determining net revenue
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 2 Page 1 of 1
Page 129
Col. 1 Col. 2 Col. 3
Line
No.Federal Provincial Combined
($Millions) ($Millions) ($Millions)
1 Utility income before income taxes 834.6 834.6
Add
2 Depreciation and amortization 714.6 714.6
3 Accrual based pension and OPEB costs 7.3 7.3
4 Other non-deductible items 130.1 130.1
5 Total Add Back 852.1 852.1
6 Sub-total 1,686.7 1,686.7
Deduct
7 Capital cost allowance 878.7 878.7
8 Items capitalized for regulatory purposes 207.3 207.3
9 Amortization of share/debenture issue expense 0.1 0.1
10 Amortization of C.D.E. and C.O.G.P.E 0.0 0.0
11 Other 1.3 1.3
12 Cash based pension and OPEB costs 18.0 18.0
13 Total Deduction 1,105.4 1,105.4
14 Taxable income 581.3 581.3
15 Income tax rates 15.00% 11.50%
16 Tax provision excluding interest shield 87.2 66.9 154.1
Tax shield on interest expense
17 Rate base 15,858.9
18 Return component of debt 2.73%
19 Interest expense 432.5
20 Combined tax rate 26.50%
21 Income tax credit (114.6)
22 Total utility income taxes 39.4
Calculation of EGI Utility Taxable Income and Income Tax Expense
2023 Actual
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 3 Page 1 of 1
Page 130
Col. 1 Col. 2
Line 2023 2022
No.Actual Actual
($Millions) ($Millions)
Property, Plant, and Equipment
1 Gross property, plant, and equipment 23,740.4 22,585.9
2 Accumulated depreciation (8,748.0) (8,320.1)
3 Net property, plant, and equipment 14,992.4 14,265.9
Allowance for Working Capital
4 Materials and supplies 110.9 102.6
5 ABC receivable (22.1) (19.4)
6 Customer security deposits (59.7) (61.0)
7 Prepaid expenses 7.2 6.1
8 Balancing gas 59.5 59.5
9 Gas in storage 748.6 1,005.1
10 Working cash allowance 22.1 22.6
11 Total Working Capital 866.5 1,115.5
12 Utility Rate Base 15,858.9 15,381.4
2023 Actual
EGI Utility Rate Base
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 1 of 9
Page 131
Col. 1 Col. 2 Col. 3
Gross Net
Property,Property,
Line Plant, and Accumulated Plant, and
No.Equipment Depreciation Equipment
($Millions) ($Millions) ($Millions)
EGD Rate Zone
1 Underground storage plant 657.0 (170.6) 486.5
2 Distribution plant 10,728.0 (3,509.5) 7,218.5
3 General plant 525.7 (355.3) 170.4
4 Plant held for future use 1.7 (1.5) 0.2
5 EGD Rate Zone Total 11,912.4 (4,036.9) 7,875.5
Union Rate Zones
6 Intangible plant 1.7 (1.6) 0.1
7 Local storage plant 33.9 (19.7) 14.2
8 Underground storage plant 826.8 (372.1) 454.7
9 Transmission plant 4,052.8 (1,365.3) 2,687.5
10 Distribution plant - Southern operations 4,098.1 (1,658.9) 2,439.2
11 Distribution plant - Northern and Eastern operations 2,390.3 (1,097.8) 1,292.4
12 General plant 424.5 (195.7) 228.7
13 Union Rate Zones Total 11,828.0 (4,711.1) 7,116.9
14 EGI Total 23,740.4 (8,748.0) 14,992.4
EGI Utility Property, Plant, and Equipment
Summary Statement - Average of Monthly Averages
2023 Actual
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 2 of 9
Page 132
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7
Opening Closing Utility Average of
Line Balance Balance Regulatory Balance Monthly
No. Dec.2022 Additions Retirements Dec.2023 Adjustment Dec.2023 Averages
($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions)
EGD Rate Zone Underground Storage Plant
1 Land and gas storage rights (450/451)48.9 0.0 (0.0) 48.9 (1.0) 47.9 47.9
2 Structures and improvements (452)35.3 0.9 (0.1) 36.2 (0.1) 36.1 35.3
3 Wells (453)95.8 (0.5) (0.4) 94.9 - 94.9 94.3
4 Well equipment (454)14.1 2.6 (0.1) 16.6 - 16.6 16.2
5 Field Lines (455)134.7 136.2 - 270.9 - 270.9 137.4
6 Compressor equipment (456)231.5 41.4 - 272.9 (0.5) 272.4 256.3
7 Measuring and regulating equipment (457)11.2 175.5 - 186.7 - 186.7 37.3
8 Base pressure gas (458)32.4 - - 32.4 - 32.4 32.4
9 Sub-Total 603.9 356.1 (0.5) 959.5 (1.5) 958.0 657.0
EGD Rate Zone Distribution Plant
10 Renewable Natural Gas (461)5.2 - - 5.2 - 5.2 5.2
11 Land (470)71.2 6.5 (0.5) 77.2 - 77.2 76.1
12 Offers to purchase (470)- - - - - - -
13 Land rights intangibles (471)63.8 0.3 - 64.0 - 64.0 63.9
14 Structures and improvements (472)190.1 5.3 (4.5) 190.9 (0.3) 190.6 190.4
15 Services, house reg & meter install. (473/474)3,679.5 236.8 (17.4) 3,899.0 - 3,899.0 3,766.0
16 Mains (475)5,288.4 174.3 (47.6) 5,415.1 (2.2) 5,412.9 5,358.5
17 NGV station compressors (476)5.2 0.7 - 6.0 - 6.0 5.6
18 Measuring and regulating equip. (477)685.2 42.9 (2.5) 725.6 (0.5) 725.1 705.3
19 Meters (478)554.2 37.9 (18.4) 573.8 - 573.8 557.1
20 Sub-Total 10,542.9 504.8 (90.9) 10,956.8 (3.1) 10,953.8 10,728.0
EGD Rate Zone General Plant
21 Investment in leased assets (101)15.3 1.0 - 16.3 - 16.3 15.8
22 Lease improvements (482)0.1 - - 0.1 (0.2) (0.1) (0.1)
23 Office furniture and equipment (483)26.9 1.2 (4.8) 23.2 - 23.2 26.7
24 Transportation equipment (484)73.9 2.5 (0.2) 76.2 (0.1) 76.1 74.3
25 NGV conversion kits (484)3.1 0.1 - 3.2 - 3.2 3.1
26 Heavy work equipment (485)26.8 1.6 - 28.4 - 28.4 27.4
27 Tools and work equipment (486)51.9 0.3 (1.5) 50.7 - 50.7 53.0
28 Rental equipment (487)2.5 0.3 - 2.8 - 2.8 2.5
29 NGV rental compressors (487)4.0 (0.0) - 4.0 - 4.0 3.5
30 NGV cylinders (484 and 487)0.6 - - 0.6 - 0.6 0.6
31 Communication structures & equip. (488)2.0 - (0.1) 1.8 - 1.8 2.0
32 Computer equipment (490)0.9 8.2 6.9 16.0 - 16.0 11.9
33 Software Aquired/Developed (491)230.0 38.1 (134.1) 133.9 - 133.9 199.1
34 CIS (491)12.2 2.0 (15.3) (1.2) - (1.2) 18.3
35 WAMS (489)92.0 - (24.2) 67.9 - 67.9 87.4
36 Sub-Total 542.2 55.2 (173.4) 424.0 (0.3) 423.7 525.7
EGD Rate Zone Plant held for future use
37 Inactive services (102)1.7 - - 1.7 - 1.7 1.7
38 EGD Rate Zone Total 11,690.7 916.1 (264.8) 12,342.0 (4.8) 12,337.1 11,912.4
Union Rate Zones Intangible Plant
EGI Utility Gross Plant
Year End Balances and Average of Monthly Averages
2023 Actual
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 3 of 9
Page 133
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7
Opening Closing Utility Average of
Line Balance Balance Regulatory Balance Monthly
No. Dec.2022 Additions Retirements Dec.2023 Adjustment Dec.2023 Averages
($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions)
EGI Utility Gross Plant
Year End Balances and Average of Monthly Averages
2023 Actual
39 Franchises and consents (401)1.2 - - 1.2 - 1.2 1.2
40 Other intangible plant (402)0.5 - - 0.5 - 0.5 0.5
41 Sub-Total 1.7 - - 1.7 - 1.7 1.7
Union Rate Zones Local Storage Plant
42 Land (440)0.0 - - 0.0 - 0.0 0.0
43 Structures and improvements (442)5.8 0.1 - 5.9 - 5.9 5.8
44 Gas holders - storage (443)5.5 0.0 - 5.5 - 5.5 5.5
45 Gas holders - equipment (443)20.2 0.2 - 20.5 - 20.5 20.3
46 Regulatory Overheads 2.3 0.5 - 2.8 - 2.8 2.4
47 Sub-Total 33.8 0.8 - 34.6 - 34.6 33.9
Union Rate Zones Underground Storage Plant
48 Land (450)11.0 0.0 - 11.0 - 11.0 11.0
49 Land rights (451)32.0 0.0 - 32.0 - 32.0 32.0
50 Structures and improvements (452)70.7 0.5 (0.2) 71.0 - 71.0 70.8
51 Wells (453)49.2 0.5 - 49.8 - 49.8 49.3
52 Field Lines (455)54.3 5.2 (0.0) 59.5 - 59.5 55.7
53 Compressor equipment (456)479.1 2.6 - 481.7 - 481.7 480.1
54 Measuring and regulating equipment (457)63.1 0.3 - 63.5 - 63.5 63.2
55 Base pressure gas (458)36.2 - - 36.2 - 36.2 36.2
56 Regulatory Overheads 27.7 2.0 - 29.7 - 29.7 28.4
57 Sub-Total 823.4 11.2 (0.2) 834.4 - 834.4 826.8
Union Rate Zones Transmission Plant
58 Land (460)85.7 (0.2) - 85.4 - 85.4 85.6
59 Land rights (461)68.6 (0.2) - 68.4 - 68.4 68.5
60 Structures & improvements (462/463/464)168.2 0.2 - 168.5 - 168.5 168.3
61 Mains (465)2,066.3 17.2 - 2,083.6 - 2,083.6 2,071.9
62 Compressor equipment (466)958.7 1.8 - 960.6 - 960.6 959.0
63 Measuring & regulating equipment (467)418.8 12.0 - 430.8 - 430.8 422.2
64 Line Pack Gas 7.2 - - 7.2 - 7.2 7.2
65 Regulatory Overheads 260.4 28.6 - 289.0 - 289.0 270.1
66 Sub-Total 4,033.9 59.5 - 4,093.4 - 4,093.4 4,052.8
Union Rate Zones Distribution Plant - Southern Operations
67 Land (470)18.5 0.5 (0.3) 18.7 - 18.7 18.5
68 Land rights (471)10.9 0.5 - 11.4 - 11.4 11.0
69 Structures and improvements (472)155.8 0.8 (0.8) 155.8 - 155.8 155.9
70 Services - metallic (473)139.3 4.1 - 143.5 - 143.5 140.4
71 Services - plastic (473)1,038.5 47.3 - 1,085.8 - 1,085.8 1,061.1
72 Regulators (474)112.2 8.6 (2.7) 118.1 - 118.1 112.8
73 House regulators & meter installations (474)89.9 6.7 - 96.6 - 96.6 91.0
74 Mains - metallic (475)724.6 37.1 - 761.6 - 761.6 730.9
75 Mains - plastic (475)803.7 38.2 - 841.9 - 841.9 817.4
76 Measuring & regulating equipment (477)91.3 12.6 - 103.9 - 103.9 93.6
77 Meters (478)414.3 53.5 (9.4) 458.4 - 458.4 434.8
78 Regulator Overheads 406.6 74.5 - 481.1 - 481.1 430.8
79 Sub-total 4,005.6 284.5 (13.3) 4,276.8 - 4,276.8 4,098.1
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 4 of 9
Page 134
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7
Opening Closing Utility Average of
Line Balance Balance Regulatory Balance Monthly
No. Dec.2022 Additions Retirements Dec.2023 Adjustment Dec.2023 Averages
($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions)
EGI Utility Gross Plant
Year End Balances and Average of Monthly Averages
2023 Actual
Union Rate Zones Distribution Plant - Northern & Eastern Operations
80 Land (470)6.3 0.3 - 6.6 - 6.6 6.4
81 Land rights (471)11.3 0.2 - 11.5 - 11.5 11.5
82 Structures and improvements (472)73.9 0.7 (3.2) 71.5 - 71.5 73.4
83 Services - metallic (473)113.2 2.3 - 115.5 - 115.5 114.4
84 Services - plastic (473)521.3 15.5 - 536.8 - 536.8 527.3
85 Regulators (474)39.4 4.1 (0.6) 42.9 - 42.9 41.3
86 House regulators & meter installations (474)45.9 0.9 - 46.8 - 46.8 46.3
87 Mains - metallic (475)795.3 43.3 - 838.5 - 838.5 804.4
88 Mains - plastic (475)251.2 12.3 - 263.5 - 263.5 252.1
89 Measuring & regulating equipment (477)161.8 6.9 - 168.7 - 168.7 162.8
90 Meters (478)108.8 8.9 (2.1) 115.6 - 115.6 110.6
91 Regulator Overheads 238.3 0.5 - 238.8 - 238.8 239.7
92 Sub-total 2,366.9 95.8 (5.9) 2,456.8 - 2,456.8 2,390.3
Union Rate Zones General Plant
93 Land (480)0.5 - - 0.5 - 0.5 0.5
94 Structures & improvements (482)98.5 0.1 - 98.5 - 98.5 98.5
95 Office furniture and equipment (483)7.8 0.0 - 7.8 - 7.8 7.7
96 Office equipment - computers (483)100.4 6.8 (70.6) 36.7 - 36.7 97.8
97 Transportation equipment (484)68.5 1.6 (2.4) 67.7 - 67.7 68.3
98 Heavy work equipment (485)23.8 1.1 (0.1) 24.9 - 24.9 24.1
99 Tools and work equipment (486)33.4 1.1 - 34.4 - 34.4 33.8
100 NGV fuel equipment (487)4.5 0.0 - 4.5 - 4.5 4.5
101 Communication equipment (488)9.3 0.0 (0.2) 9.2 - 9.2 9.3
102 Regulatory Overheads 79.3 3.6 (17.2) 65.6 - 65.6 79.9
103 Sub-total 426.1 14.2 (90.4) 350.0 - 350.0 424.5
104 Union Rate Zones Total 11,691.4 466.0 (109.8) 12,047.7 - 12,047.7 11,828.0
105 EGI Total 23,382.1 1,382.1 (374.6) 24,389.6 (4.8) 24,384.8 23,740.4
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 5 of 9
Page 135
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8
Opening Costs Closing Utility Average of
Line Balance Net of Balance Regulatory Balance MonthlyNo.Dec.2022 Additions Retirements Proceeds Dec.2023 Adjustment Dec.2023 Averages
($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions)EGD Rate Zone Underground Storage Plant
1 Land and gas storage rights (451)(27.6) (0.5) - - (28.1) - (28.1) (27.8) 2 Structures and improvements (452)(3.4) (0.6) - (0.0) (4.0) 0.1 (4.0) (3.7)
3 Wells (453)(16.9) (1.4) 0.4 - (17.9) - (17.9) (17.7)
4 Well equipment (454)(9.3) (1.1) 0.1 - (10.4) - (10.4) (9.9) 5 Field Lines (455)(35.9) (2.1) - - (38.0) - (38.0) (36.9)
6 Compressor equipment (456)(63.0) (6.0) - - (69.0) 0.3 (68.7) (65.7)
7 Measuring and regulating equipment (457)(8.6) (1.0) - - (9.6) - (9.6) (8.8)
8 Sub-Total (164.8) (12.7) 0.5 (0.0) (177.0) 0.4 (176.6) (170.6)
EGD Rate Zone Distribution Plant
9 Renewable Natural Gas (461)(0.0) - - - (0.0) - (0.0) (0.0)
10 Land rights intangibles (471)(7.2) (0.8) - - (8.0) - (8.0) (7.6)
11 Structures and improvements (472)(51.2) (11.7) 12.9 (11.2) (61.2) 0.3 (60.8) (54.3)
12 Services, house reg & meter install. (473/474)(1,182.5) (84.2) 17.4 35.2 (1,214.1) - (1,214.1) (1,200.3)
13 Mains (475)(1,585.2) (118.5) 11.0 13.7 (1,679.0) 2.2 (1,676.8) (1,624.7)
14 NGV station compressors (476)(3.9) (0.4) - - (4.2) - (4.2) (4.1)
15 Measuring and regulating equip. (477)(247.4) (16.1) 2.5 0.4 (260.5) 0.5 (260.0) (252.7)
16 Meters (478)(354.3) (45.1) 18.4 0.0 (381.0) - (381.0) (365.8)
17 Sub-Total (3,431.7) (276.7) 62.2 38.2 (3,608.1) 3.1 (3,605.0) (3,509.5)
EGD Rate Zone General Plant
18 Investment in leased assets (101)(0.4) (0.5) - - (0.9) - (0.9) (0.6) 19 Lease improvements (482)(0.1) - - - (0.1) 0.2 0.1 0.1
20 Office furniture and equipment (483)(18.3) (2.2) 0.8 - (19.8) - (19.8) (18.8)
21 Transportation equipment (484)(44.1) (7.9) 0.2 - (51.8) 0.1 (51.7) (47.9) 22 NGV conversion kits (484) (0.1) (0.3) - - (0.4) - (0.4) (0.3)
23 Heavy work equipment (485)(7.5) (1.0) - - (8.6) - (8.6) (8.1)
24 Tools and work equipment (486)(9.7) (2.1) 1.5 - (10.3) - (10.3) (10.5)
25 Rental equipment (487)(0.1) (0.0) - - (0.1) - (0.1) (0.1)
26 NGV rental compressors (487)(3.1) (2.1) 1.2 - (4.0) - (4.0) (3.4)
27 NGV cylinders (484 and 487)(0.6) (0.0) - - (0.6) - (0.6) (0.6)
28 Communication structures & equip. (488)(0.1) (0.2) 0.1 - (0.1) - (0.1) (0.1)
29 Computer equipment (490)0.4 (6.1) (7.4) - (13.1) - (13.1) (11.1)
30 Software Aquired/Developed (491)(199.7) (53.2) 119.0 - (133.9) - (133.9) (185.1)
31 CIS (491)(9.3) 4.7 5.8 - 1.2 - 1.2 (10.6)
32 WAMS (489)(56.8) (10.6) 18.5 - (48.9) - (48.9) (58.2)
33 Sub-Total (349.5) (81.6) 139.8 - (291.3) 0.3 (291.0) (355.3)
EGD Rate Zone Plant held for future use
34 Inactive services (102)(1.5) (0.0) - - (1.5) - (1.5) (1.5)
35 EGD Rate Zone Total (3,947.5) (371.0) 202.5 38.2 (4,077.9) 3.7 (4,074.2) (4,036.9)
Union Rate Zones Intangible Plant
36 Franchises and consents (401)(1.0) (0.1) - - (1.1) - (1.1) (1.1)
37 Other intangible plant (402)(0.5) (0.0) - - (0.5) - (0.5) (0.5)
38 Sub-Total (1.5) (0.1) - - (1.6) - (1.6) (1.6)
EGI Utility Plant
Continuity of Accumulated Depreciation
Year End Balances and Average of Monthly Averages
2023 Actual
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 6 of 9
Page 136
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8
Opening Costs Closing Utility Average of
Line Balance Net of Balance Regulatory Balance Monthly
No.Dec.2022 Additions Retirements Proceeds Dec.2023 Adjustment Dec.2023 Averages
EGI Utility Plant
Continuity of Accumulated Depreciation
Year End Balances and Average of Monthly Averages
2023 Actual
Union Rate Zones Local Storage Plant
39 Structures and improvements (442)(2.7) (0.2) - - (2.9) - (2.9) (2.8)
40 Gas holders - storage (443) (4.1) (0.1) - - (4.2) - (4.2) (4.1)
41 Gas holders - equipment (443)(11.7) (0.7) - - (12.4) - (12.4) (12.1) 42 Regulatory Overheads (0.6) (0.1) - - (0.7) - (0.7) (0.7)
43 Sub-Total (19.1) (1.1) - - (20.2) - (20.2) (19.7)
Union Rate Zones Underground Storage Plant
44 Land rights (451)(19.4) (0.7) - - (20.1) - (20.1) (19.8)
45 Structures and improvements (452)(45.6) (1.8) 0.2 - (47.2) - (47.2) (46.5)
46 Wells (453) (35.4) (1.2) - 0.0 (36.6) - (36.6) (36.0)
47 Field Lines (455) (30.9) (1.4) 0.0 - (32.2) - (32.2) (31.6)
48 Compressor equipment (456) (180.7) (12.9) - 0.0 (193.6) - (193.6) (187.1)
49 Measuring & regulating equipment (457)(44.9) (1.9) - - (46.9) - (46.9) (45.9)
50 Regulatory Overheads (4.8) (0.9) - - (5.7) - (5.7) (5.2)
51 Sub-Total (361.8) (20.7) 0.2 0.0 (382.3) - (382.3) (372.1)
Union Rate Zones Transmission Plant
52 Land rights (461)(20.5) (1.2) - - (21.7) - (21.7) (21.1) 53 Structures & improvements (462/463/464)(50.2) (3.4) - - (53.6) - (53.6) (51.9)
54 Mains (465)(733.0) (41.2) - 0.1 (774.1) - (774.1) (753.5)
55 Compressor equipment (466)(354.9) (31.0) - 0.0 (385.9) - (385.9) (370.4) 56 Measuring & regulating equipment (467)(125.5) (11.3) - 0.3 (136.5) - (136.5) (131.2)
57 Regulatory Overheads (34.0) (6.7) - - (40.7) - (40.7) (37.3)
58 Sub-Total (1,318.0) (94.8) - 0.4 (1,412.5) - (1,412.5) (1,365.3)
Union Rate Zones Distribution Plant - Southern Operations
59 Land rights (471)(2.6) (0.2) - - (2.8) - (2.8) (2.7)
60 Structures and improvements (472)(50.7) (3.4) 0.4 - (53.7) - (53.7) (52.3)
61 Services - metallic (473) (110.2) (4.0) - 4.2 (109.9) - (109.9) (111.4)
62 Services - plastic (473) (457.1) (26.8) - 36.2 (447.6) - (447.6) (457.3)
63 Regulators (474) (41.0) (5.6) 2.7 0.2 (43.7) - (43.7) (43.5)
64 House regulators & meter installations (474)(34.6) (2.5) - 0.0 (37.1) - (37.1) (35.9)
65 Mains - metallic (475)(392.8) (20.7) - 0.3 (413.2) - (413.2) (402.9)
66 Mains - plastic (475)(317.9) (18.9) - 0.0 (336.7) - (336.7) (327.2)
67 Measuring & regulating equipment (477)(26.1) (3.4) - 0.2 (29.4) - (29.4) (27.8)
68 Meters (478) (124.6) (16.3) 9.4 (0.2) (131.6) - (131.6) (127.3)
69 Regulator Overheads (64.5) (12.4) - - (76.9) - (76.9) (70.7)
70 Sub-Total (1,622.0) (114.1) 12.5 40.9 (1,682.7) - (1,682.7) (1,658.9)
Union Rate Zones Distribution Plant - Northern & Eastern Operations
71 Land rights intangibles (471)(4.7) (0.2) - - (4.9) - (4.9) (4.8)
72 Structures and improvements (472)(30.1) (1.8) 0.0 - (31.8) - (31.8) (31.0) 73 Services - metallic (473) (84.4) (3.7) - 0.7 (87.3) - (87.3) (86.0)
74 Services - plastic (473) (242.8) (13.8) - 0.7 (255.9) - (255.9) (249.5)
75 Regulators (474) (15.3) (2.1) 0.6 0.0 (16.7) - (16.7) (16.2) 76 House regulators & meter installations (474)(18.8) (1.4) - 0.1 (20.1) - (20.1) (19.5)
77 Mains - metallic (475)(386.9) (24.3) - (0.0) (411.2) - (411.2) (399.0)
78 Mains - plastic (475)(125.3) (6.0) - 0.0 (131.3) - (131.3) (128.3) 79 Measuring & regulating equipment (477)(88.6) (6.1) - 0.1 (94.6) - (94.6) (91.5)
80 Meters (478) (31.5) (4.4) 2.1 0.0 (33.7) - (33.7) (32.6)
81 Regulator Overheads (36.2) (6.7) - - (42.9) - (42.9) (39.4)
82 Sub-Total (1,064.5) (70.4) 2.8 1.7 (1,130.5) - (1,130.5) (1,097.8)
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 7 of 9
Page 137
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8
Opening Costs Closing Utility Average of
Line Balance Net of Balance Regulatory Balance Monthly
No.Dec.2022 Additions Retirements Proceeds Dec.2023 Adjustment Dec.2023 Averages
EGI Utility Plant
Continuity of Accumulated Depreciation
Year End Balances and Average of Monthly Averages
2023 Actual
Union Rate Zones General Plant
83 Structures & improvements (482)(19.1) (2.0) - - (21.1) - (21.1) (20.1)
84 Office furniture and equipment (483)(4.7) (0.5) - - (5.2) - (5.2) (4.9)
85 Office equipment - computers (483) (35.2) (17.5) 26.7 - (26.0) - (26.0) (42.9) 86 Transportation equipment (484)(57.2) (9.2) 2.4 (0.7) (64.7) - (64.7) (61.5)
87 Heavy work equipment (485) (6.9) (1.7) 0.1 - (8.6) - (8.6) (7.8)
88 Tools and work equipment (486) (14.9) (2.3) - - (17.1) - (17.1) (16.0) 89 NGV fuel equipment (487)(1.7) (0.2) - - (1.9) - (1.9) (1.8)
90 Communication equipment (488)(5.5) (0.6) 0.1 - (6.0) - (6.0) (5.8)
91 Regulatory Overheads (31.2) (8.0) 7.9 - (31.3) - (31.3) (34.8)
92 Sub-Total (176.4) (42.0) 37.2 (0.7) (181.9) - (181.9) (195.7)
93 Union Rate Zones Total (4,563.5) (343.3) 52.7 42.3 (4,811.7) - (4,811.7) (4,711.1)
94 EGI Total (8,511.0) (714.3) 255.2 80.5 (8,889.6) 3.7 (8,885.9) (8,748.0)
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 8 of 9
Page 138
EGI Working Capital Components
Month End Balances and Average of Monthly Averages
2023 Actual
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8
Materials Customer Working
Line and ABC Security Prepaid Balancing Gas in Cash
No. Supplies Receivable Deposits Expenses Gas Storage Allowance Total
($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions) ($Millions)
1 January 1 96.2 (18.5) (59.9) (0.1) 59.5 1,422.9 22.1 1,522.2
2 January 31 100.1 8.3 (59.8) (9.7) 59.5 978.9 22.1 1,099.3
3 February 103.1 (25.5) (59.8) (1.1) 59.5 875.4 22.1 973.8
4 March 107.9 (51.9) (57.3) 3.4 59.5 634.8 22.1 718.5
5 April 110.6 (40.0) (57.8) 7.6 59.5 395.1 22.1 497.1
6May 116.7 (37.8) (58.4) 7.0 59.5 448.7 22.1 557.9
7 June 109.3 (44.9) (56.4) 11.4 59.5 561.7 22.1 662.7
8 July 112.3 (22.7) (57.2) 9.7 59.5 613.0 22.1 736.8
9 August 114.5 (13.8) (58.5) 14.9 59.5 738.8 22.1 877.4
10 September 114.7 (18.0) (61.3) 18.8 59.5 857.9 22.1 993.8
11 October 115.7 (0.6) (65.3) 15.1 59.5 936.4 22.1 1,082.9
12 November 118.8 (0.0) (63.5) 10.3 59.5 835.6 22.1 982.7
13 December 118.5 (18.8) (63.3) (0.8) 59.5 791.0 22.1 908.3
14 Avg. of monthly avgs.110.9 (22.1) (59.7) 7.2 59.5 748.6 22.1 866.5
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 4 Page 9 of 9
Page 139
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5
(Col. 1x Col. 3)
Line Return Interest
No.Principal Component Cost Rate Component & Return
($Millions) % % % ($Millions)
1 Long and Medium-Term Debt 9,498.1 59.89 4.21 2.520 399.7
2 Short-Term Debt 651.6 4.11 5.04 0.207 32.9
3 Total Debt 10,149.7 64.00 2.727 432.5
4 Common Equity 5,709.2 36.00 10.86 3.910 620.0
5 Total Rate Base 15,858.9 100.00 6.637 1,052.6
EGI Summary of Capital Structure & Cost of Capital
2023 Actual
Utility Capital Structure
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 5 Page 1 of 4
Page 140
Calculation of Cost Rates
for EGI Capital Structure Components
2023 Actual
Col. 1 Col. 2 Col. 3
Average of
Line Monthly Carrying
No.Averages Cost
($Millions)($Millions)
Long and Medium-Term Debt
1 Debt Summary 9,792.9 410.7
2 Unamortized Finance Costs (33.2) -
3 (Profit)/Loss on Redemption - -
4 9,759.7 410.7
5 Percentage Allocation of Debt to Unregulated 2.68% (261.6) (11.0)
6 Net Regulated Long and Medium-Term Debt 9,498.1 399.7
7 Calculated Cost Rate 4.21%
Short-Term Debt
8 Calculated Cost Rate 5.04%
Common Equity
9 Board Formula ROE 9.36%
10 Threshold before earnings sharing 1.50%
11 ROE for earnings sharing determination 10.86%
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 5 Page 2 of 4
Page 141
EGI Summary Statement of Principal and Carrying Cost of Term Debt
2023 Actual
Col. 1 Col. 2 Col. 3
Average of
Line Coupon Monthly Averages Effective Carrying
No. Rate Maturity Date Principal Cost Rate Cost
($Millions)($Millions)
Medium Term Notes
1 4.20% June 2, 2044 250.0 4.24% 10.6
2 4.20% June 2, 2044 250.0 4.27% 10.7
3 6.05% September 2, 2038 300.0 6.10% 18.3
4 4.88% June 21, 2041 300.0 4.92% 14.8
5 5.20% July 23, 2040 250.0 5.27% 13.2
6 3.79% July 10, 2023 135.4 3.87% 5.2
7 2.81% June 1, 2026 250.0 2.87% 7.2
8 3.80% June 1, 2046 250.0 3.84% 9.6
9 2.88% November 22, 2027 250.0 2.95% 7.4
10 3.59% November 22, 2047 250.0 3.64% 9.1
11 3.19% September 17, 2025 200.0 3.26% 6.5
12 5.46% September 11, 2036 165.0 5.49% 9.1
13 8.65% November 10, 2025 125.0 8.77% 11.0
14 4.85% April 25, 2022 - 4.91% -
15 8.85% October 2, 2025 20.0 8.97% 1.8
16 7.60% October 29, 2026 100.0 8.09% 8.1
17 6.65% November 3, 2027 100.0 6.71% 6.7
18 6.10% May 19, 2028 100.0 6.16% 6.2
19 6.05% July 5, 2023 54.2 6.38% 3.5
20 6.90% November 15, 2032 150.0 6.95% 10.4
21 6.16% December 16, 2033 150.0 6.18% 9.3
22 5.21% February 25, 2036 300.0 5.18% 15.5
23 4.95% November 22, 2050 200.0 4.99% 10.0
24 4.95% November 22, 2050 100.0 4.73% 4.7
25 4.50% November 23, 2043 200.0 4.20% 8.4
26 3.15% August 22, 2024 215.0 3.24% 7.0
27 4.00% August 22, 2044 215.0 3.89% 8.4
28 4.00% August 22, 2044 170.0 4.44% 7.5
29 3.31% September 11, 2025 400.0 3.62% 14.5
30 2.50% August 5, 2026 300.0 3.42% 10.3
31 3.51% November 29, 2047 300.0 3.53% 10.6
32 2.37% August 9, 2029 400.0 3.23% 12.9
33 3.01% August 9, 2049 300.0 3.03% 9.1
34 2.90% April 1, 2030 600.0 3.41% 20.4
35 3.65% April 1, 2050 600.0 3.67% 22.0
36 2.35% September 1, 2031 475.0 2.94% 14.0
37 3.20% September 1, 2051 425.0 3.22% 13.7
38 4.15% August 17, 2032 325.0 3.15% 10.2
39 4.55% August 17, 2052 325.0 4.52% 14.7
40 5.46% October 6, 2028 52.1 5.54% 2.9
41 5.70% October 6, 2033 83.3 3.70% 3.1
42 5.67% October 6, 2053 72.9 5.08% 3.7
43 9,707.9 402.3
Long-Term Debentures
44. 9.85% December 2, 2024 85.0 9.910% 8.4
45.85.0 8.4
46. Total Term Debt 9,792.9 410.7
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 5 Page 3 of 4
Page 142
EGI Unamortized Debt Discount and Expense
Average of Monthly Averages
Col. 1
Unamortized
Line Debt Discount
No.and Expense
($Millions)
1 January 1 69.5
2 January 31 68.6
3 February 67.7
4 March 66.8
5 April 65.9
6 May 65.0
7 June 64.1
8 July 63.2
9 August 62.4
10 September 61.8
11 October (80.2)
12 November (94.7)
13 December (94.6)
14 Average of Monthly Averages 33.2
2023 Actual
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 5 Page 4 of 4
Page 143
Col. 1 Col. 2 Col. 3 Col. 4
Audited Corporate
Income Income
Line
No. ($ millions)
(as per Financial
Statements)
(as per Utility
Income Schedule) Variance Reference
Operating Revenues
1 Gas sales and distribution 4,797.2 5,398.3
2 Storage, transportation and other 1,045.5 -
3 Transportation - 140.4
4 Storage - 215.2
5 Other operating revenue - 76.6
6 Other Income 47.5 11.1
7 Total operating revenue 5,890.3 5,841.6 (48.7) (a)
Operating Expenses
8 Gas Costs 2,873.4 2,873.4 (0.0)
9 Operation and maintenance 1,196.7 1,303.2 106.5 (b)
10 Depreciation and amortization expense 756.6 756.6 (0.0)
11 Impairment of long-lived assets 281.5 - (281.5) (b)
12 Fixed financing costs - 4.0 4.0 (c)
13 Municipal and other taxes - 126.3 126.3 (d)
14 Cost of service 5,108.2 5,063.5 (44.7)
15 Income before interest and income taxes 782.1 778.1 (4.0)
16 Interest and financing expenses 439.5 - (439.5) (e)
17 Income before income taxes 342.6 778.1 435.5
18 Income taxes 1.5 - (1.5) (f)
19 Net Income 341.1 778.1 437.0
Col. 2 - Corporate income as reported in Exhibit B, Tab 1, Schedule 2, Column 1
a)Audited Total Operating Revenue 5,890.3
Reclassify pension related other revenue to O&M (37.0)
Reclassify EGD rate zone Open Bill and ABC T-service O&M against program revenues in other revenue (12.3)
Reclassify other expenses out of other income to O&M 0.6
Corporate Total Operating Revenue 5,841.6
b)Audited Operation and Maintenance 1,196.7
Reclassify pension related other revenue to O&M (37.0)
Reclassify Municipal & Property Taxes out of O&M (126.3)
Reclassify Impairment Charges to O&M 281.5
Reclassify EGD rate zone Open Bill and ABC T-service O&M against program revenues in other revenue (12.3)
Reclassify other expenses out of other income to O&M 0.6
Corporate Operation and Maintenance 1,303.2
c)Audited Fixed Financing Costs -
Reclassify fixed financing costs from interest and financing expenses 4.0
Corporate Fixed Financing Costs 4.0
d)Audited Municipal and Other Taxes -
Reclassify Municipal and other taxes included within O&M costs 126.3
Corporate Municipal and Other Taxes 126.3
e)Audited Interest and Financing expenses 439.5
Reclassify fixed financing costs from interest and financing expenses (4.0)
Elimination of interest expense and the amortization of debt issue and discount costs
which are determined through the regulated capital structure
Corporate Interest and Financing expenses (0.0)
f)Audited Income Taxes 1.5
Elimination of corporate income taxes which will be calculated on a utility stand-alone basis (1.5)
Corporate Income Taxes -
Reconciliation of Audited Enbridge Gas Inc. Income (Per Financial Statements) to Corporate Income for Utility Income Determination Purposes
2023 Actual
(435.5)
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 1
Schedule 6 Page 1 of 1
Page 144
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6
Line
No.Sales ABC-T ABC-Unbundled Bundled-T T-Service Total
1 General Service2Rate 1 995.1 13.6 - 0.0 - 1,008.7
3 Rate 6 312.8 83.7 - 28.3 - 424.7 4 Rate 9 - - - -- -
5 Total EGD Rate Zone 1,307.9 97.2 - 28.3 - 1,433.4
6 Rate M1 508.6 18.2 - 1.7 - 528.5 7 Rate M2 37.8 28.2 - 17.7 - 83.8 8 Rate 01 190.5 8.2 - 1.0 - 199.7 9 Rate 10 11.9 7.4 - 5.3 0.2 24.7 10 Total Union Rate Zones 748.8 62.1 - 25.7 0.2 836.7
11 Total General Service Sales & T-Service 2,056.7 159.3 - 54.0 0.2 2,270.1
12 Wholesale - Utility13Rate M9 0.7 - - 1.3 - 2.0 14 Rate M10 0.0 - - - - 0.0 15 Total Wholesale - Utility 0.7 - - 1.3 - 2.0
16 Contract Sales
17 Rate 100 0.8 0.6 - 1.5 - 2.9 18 Rate 110 4.4 7.1 - 28.8 - 40.3 19 Rate 115 0.0 - - 6.5 - 6.5 20 Rate 125 - - - - 12.7 12.7 21 Rate 135 0.2 0.2 - 1.5 - 1.8 22 Rate 145 0.0 0.3 - 3.5 - 3.8 23 Rate 170 0.0 0.2 - 2.5 - 2.7
24 Rate 200 3.3 - - 1.6 - 5.0 25 Rate 300 - - - - 0.0 0.0
26 Rate 315 - - - - 0.0 0.0 27 Total EGD Rate Zone 8.7 8.3 - 46.0 12.7 75.7
28 Rate M4 4.0 3.1 - 28.2 - 35.2 29 Rate M7 1.5 1.4 - 26.2 - 29.1 30 Rate 20 0.9 0.1 - 3.3 27.3 31.7 31 Rate 100 - - - - 11.1 11.1
32 Rate T-1 - - - - 14.0 14.0 33 Rate T-2 - - - - 82.3 82.3 34 Rate T-3 - - - - 7.6 7.6 35 Rate M5 0.2 0.2 - 2.3 - 2.7 36 Rate 25 2.2 - - - 7.1 9.3 37 Rate 30 - - - - - - 38 Total Union Rate Zones 8.9 4.8 - 60.0 149.5 223.2
39 Total Contract Sales 17.6 13.1 - 106.0 162.2 298.9
40 Subtotal 2,075.0 172.4 - 161.2 162.4 2,571.0
41 Accounting Adjustments:
42 EGI Tax Variance (18.7) - - - (4.4) (27.2) 43 EGI Accounting Policy Change - - - - - (40.3)
44 EGD Average Use / Normalized Average Consumption 9.8 45 EGD Dawn Access COS (DACDA)
46 EGD Incremental Capital Module 4.1 47 EGD LRAM (0.0) 48 EGD Febderal Carbon Program 0.6 0.1 0.2 0.1 0.9 49 EGI Greenhouse Gas Emissions Administration 0.1 50 Union Average Use / Normalized Average Consumption (4.1) 51 Union Incremental Capital Module 1.8 52 Union Capital Pass-through (1.7)
53 Union Parkway Obligation (0.0) 54 Union LRAM 0.5 55 Union DSM 1.4 1.4 56 Union Federal Carbon Program 0.7 0.1 0.3 1.2 2.3 57 Elimination of the UGL rate zone unregulated storage cost from EGD rate zone revenues (17.3)
58 Total Utility Revenue 2,501.2
($ Millions)
Delivery Revenue by Service, Rate Class and Service Class
Enbridge Gas Inc.
For the Year Ending December 31, 2023
Revenues
Filed: 2024-05-31 EB-2024-0125 Exhibit B Tab 2 Schedule 1 Page 1 of 2
Page 145
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6
LineNo.Sales ABC-T ABC-Unbundled Bundled-T T-Service Total
1 General Service2Rate 1 982.7 15.0 - 0.1 - 997.8 3 Rate 6 319.0 82.8 - 31.7 - 433.6 4 Rate 9 (0.0) - - - - (0.0) 5 Total EGD Rate Zone 1,301.7 97.8 - 31.8 - 1,431.4
6 Rate M1 500.6 18.5 - 1.7 - 520.7 7 Rate M2 38.2 26.4 - 16.5 - 81.2 8 Rate 01 188.2 8.2 - 1.0 - 197.4
9 Rate 10 11.6 6.9 - 5.0 0.3 23.8 10 Total Union Rate Zones 738.6 59.9 - 24.1 0.3 823.0
11 Total General Service 2,040.3 157.7 - 56.0 0.3 2,254.4
12 Wholesale - Utility
13 Rate M9 0.7 - - 1.3 - 1.9 14 Rate M10 0.0 - - - - 0.0 15 Total Wholesale - Utility 0.7 - - 1.3 - 2.0
16 Contract Sales
17 Rate 100 0.7 0.4 - 1.2 - 2.3 18 Rate 110 3.6 5.5 - 27.3 - 36.5 19 Rate 115 0.0 - - 6.8 - 6.9
20 Rate 125 - - - - 12.2 12.2 21 Rate 135 0.2 0.3 - 1.1 - 1.6
22 Rate 145 0.1 0.2 - 1.4 - 1.7 23 Rate 170 0.1 0.2 - 3.2 - 3.5 24 Rate 200 3.3 - - 1.5 - 4.8
25 Rate 300 - - - - 0.1 0.1 26 Rate 315 - - - - 0.0 0.0 27 Total EGD Rate Zone 8.0 6.7 - 42.6 12.3 69.6
28 Rate M4 4.7 2.8 - 27.6 - 35.1 29 Rate M7 2.6 1.2 - 23.3 - 27.0 30 Rate 20 0.9 0.1 - 3.1 23.7 27.8 31 Rate 100 - - - - 11.9 11.9 32 Rate T-1 - - - - 14.3 14.3 33 Rate T-2 - - - - 80.8 80.8 34 Rate T-3 - - - - 7.5 7.5 35 Rate M5 0.2 0.2 - 2.3 - 2.7 36 Rate 25 2.4 - - - 3.7 6.1
37 Rate 30 - - - - - 0.038Total Union Rate Zones 10.8 4.4 - 56.3 141.9 213.4
39 Total Contract Sales 18.8 11.1 - 98.9 154.2 282.9
40 Subtotal 2,059.8 168.8 - 156.2 154.5 2,539.3
41 Accounting Adjustments:
42 EGI Tax Variance (29.9) 43 EGI Accounting Policy Change (2.8) 44 EGD Average Use / Normalized Average Consumption 3.5
45 EGD Dawn Access COS (DACDA)1.2 46 EGD Incremental Capital Module (6.9) 47 EGD LRAM 0.1 48 EGD Febderal Carbon Program 0.9 49 EGD Greenhouse Gas Emissions Administration 0.1 50 Union Average Use / Normalized Average Consumption 6.4 51 Union Incremental Capital Module (2.0) 52 Union Capital Pass-through (2.9) 53 Union Parkway Obligation (0.1) 54 Union LRAM 0.8
55 Union Federal Carbon Program 2.0 56 Elimination of the UGL rate zone unregulated storage cost from EGD rate zone revenues (17.4)
57 Total Utility Revenue 2,492.0
For the Year Ending December 31, 2022
Revenues($ Millions)
Delivery Revenue by Service, Rate Class and Service ClassEnbridge Gas Inc.
Filed: 2024-05-31 EB-2024-0125 Exhibit B Tab 2 Schedule 1 Page 2 of 2
Page 146
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8 Col. 9
Customer Meters
LineNo.Sales T-Service Total Sales T-Service Total System Sales T-Service Total
1 General Service2Rate 1 2,124,994 27,310 2,152,304 4,614,491 62,856 4,677,347 2,069.6 15.6 2,085.2 3 Rate 6 148,013 23,197 171,210 2,800,585 1,649,573 4,450,159 968.3 157.9 1,126.2 4 Rate 9 - - - 5 Total EGD Rate Zone 2,273,007 50,507 2,323,514 7,415,076 1,712,429 9,127,506 3,037.9 173.5 3,211.4
6 Rate M1 1,168,590 28,454 1,197,044 2,744,946 180,673 2,925,618 1,062.7 19.9 1,082.6 7 Rate M2 4,902 3,715 8,617 503,869 646,755 1,150,624 135.8 45.9 181.8 8 Rate 01 358,646 10,192 368,838 869,052 62,730 931,782 428.4 14.1 442.5 9 Rate 10 1,435 959 2,394 137,667 167,581 305,249 45.1 23.1 68.2 10 Total Union Rate Zones 1,533,573 43,320 1,576,893 4,255,534 1,057,739 5,313,273 1,672.0 103.0 1,775.0
11 Total General Service Sales & T-Service 3,806,580 93,827 3,900,407 11,670,610 2,770,168 14,440,778 4,709.9 276.5 4,986.4
12 Wholesale - Utility13Rate M9 1 3 4 17,445 80,435 97,880 4.2 1.3 5.5 14 Rate M10 3 3 427 427 0.1 - 0.1 15 Total Wholesale - Utility 4 3 7 17,872 80,435 98,307 4.4 1.3 5.6
16 Contract Sales17Rate 100 6 13 19 13,666 36,350 50,015 4.0 3.1 7.1 18 Rate 110 90 376 466 120,157 1,134,071 1,254,228 28.6 50.5 79.1 19 Rate 115 18 18 158 354,870 355,028 0.0 9.3 9.3 20 Rate 125 4 4 1,106,860 1,106,860 - 12.7 12.7 21 Rate 135 2 41 43 1,651 65,218 66,869 0.4 1.9 2.3 22 Rate 145 2 15 17 (138) 50,022 49,883 (0.1) 4.5 4.5 23 Rate 170 20 20 1,559 242,401 243,960 0.2 1.9 2.1 24 Rate 200 1 1 133,901 54,540 188,441 34.7 2.7 37.4 25 Rate 300 1 1 0 0 - 0.0 0.0 26 Rate 315 - 0.0 0.0 27 Total EGD Rate Zone 101 488 589 270,954 3,044,331 3,315,285 68.0 86.6 154.5
28 Rate M4 25 196 221 51,991 512,604 564,595 13.9 31.3 45.2 29 Rate M7 1 68 69 18,856 750,681 769,537 5.6 27.7 33.3 30 Rate 20 5 60 65 8,870 1,065,356 1,074,225 3.6 37.3 40.9 31 Rate 100 11 11 942,952 942,952 - 11.1 11.1 32 Rate T-1 38 38 397,887 397,887 - 14.0 14.0 33 Rate T-2 27 27 5,069,101 5,069,101 - 82.4 82.4 34 Rate T-3 1 1 255,245 255,245 - 7.6 7.6 35 Rate M5 4 31 35 1,767 57,200 58,966 0.6 2.5 3.1 36 Rate 25 29 22 51 54,615 201,050 255,665 12.8 7.1 19.9 37 Rate 30 - - 38 Total Union Rate Zones 64 454 518 136,098 9,252,076 9,388,174 36.5 220.9 257.4
39 Total Contract Sales 165 942 1,107 407,052 12,296,407 12,703,459 104.5 307.5 412.0
40 Subtotal 3,806,749 94,772 3,901,521 12,095,534 15,147,010 27,242,544 4,818.8 585.3 5,404.0
41 Accounting Adjustments:
42 EGI Tax Variance (27.2) 43 EGI Accounting Policy Change (40.3) 44 EGD Average Use / Normalized Average Consumption 16.9 45 EGD Dawn Access COS (DACDA)- 46 EGD Incremental Capital Module 4.1 47 EGD LRAM (0.0) 48 EGD Febderal Carbon Program 0.9 49 EGI Greenhouse Gas Emissions Administration 0.1 50 EGD Transactional Services Revenue 12.0 51 Union Average Use / Normalized Average Consumption (3.7) 52 Union Incremental Capital Module 1.8 53 Union Capital Pass-through (1.7) 54 Union Parkway Obligation (0.0) 55 Union LRAM 0.5 56 Union DSM 1.4 57 Union Federal Carbon Program 2.3 58 Elimination of the UGL rate zone unregulated storage cost from EGD rate zone revenues (17.3) 59 Miscellaneous 11.9
60 Total Utility Revenue 5,365.7
(103M3)($ Millions)
Customer Meters, Volumes and Revenues by Rate ClassEnbridge Gas Inc.
For the Year Ending December 31, 2023
Throughput Volumes Revenues
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 2
Schedule 2 Page 1 of 4
Page 147
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8 Col. 9
Customer Meters
Line No.Sales T-Service Total Sales T-Service Total System Sales T-Service Total
1 General Service2Rate 1 2,124,994 27,310 2,152,304 4,851,862 66,140 4,918,002 2,148.0 16.0 2,164.0 3 Rate 6 148,013 23,197 171,210 2,947,451 1,730,393 4,677,845 1,012.6 163.2 1,175.8 4 Rate 9 - - - - - - - - - 5 Total EGD Rate Zone 2,273,007 50,507 2,323,514 7,799,314 1,796,533 9,595,847 3,160.6 179.2 3,339.8
6 Rate M1 1,168,590 28,454 1,197,044 2,976,358 195,904 3,172,262 1,127.3 20.5 1,147.8 7 Rate M2 4,902 3,715 8,617 540,935 694,331 1,235,266 146.2 49.0 195.2 8 Rate 01 358,646 10,192 368,838 930,548 67,169 997,717 452.7 14.8 467.5 9 Rate 10 1,435 959 2,394 144,968 176,469 321,437 47.8 24.3 72.1 10 Total Union Rate Zones 1,533,573 43,320 1,576,893 4,592,809 1,133,872 5,726,681 1,774.0 108.7 1,882.7
11 Total General Service Sales & T-Service 3,806,580 93,827 3,900,407 12,392,123 2,930,406 15,322,528 4,934.6 287.9 5,222.5
12 Wholesale - Utility13Rate M9 1 3 4 17,445 80,435 97,880 4.2 1.3 5.5 14 Rate M10 3 - 3 427 - 427 0.1 - 0.1 15 Total Wholesale - Utility 4 3 7 17,872 80,435 98,307 4.4 1.3 5.6
16 Contract Sales17Rate 100 6 13 19 13,666 36,350 50,015 4.0 3.1 7.1 18 Rate 110 90 376 466 120,157 1,134,071 1,254,228 28.6 50.5 79.1 19 Rate 115 - 18 18 158 354,870 355,028 0.0 9.3 9.3 20 Rate 125 - 4 4 - 1,106,860 1,106,860 - 12.7 12.7 21 Rate 135 2 41 43 1,651 65,218 66,869 0.4 1.9 2.3 22 Rate 145 2 15 17 (138) 50,022 49,883 (0.1) 4.5 4.5 23 Rate 170 - 20 20 1,559 242,401 243,960 0.2 1.9 2.1 24 Rate 200 1 - 1 133,901 54,540 188,441 34.7 2.7 37.4 25 Rate 300 - 1 1 - 0 0 - 0.0 0.0 26 Rate 315 - - - - - - - 0.0 0.0 27 Total EGD Rate Zone 101 488 589 270,954 3,044,331 3,315,285 68.0 86.6 154.5
28 Rate M4 25 196 221 51,991 512,604 564,595 13.9 31.3 45.2 29 Rate M7 1 68 69 18,856 750,681 769,537 5.6 27.7 33.3 30 Rate 20 5 60 65 8,870 1,065,356 1,074,225 3.6 37.3 40.9 31 Rate 100 - 11 11 - 942,952 942,952 - 11.1 11.1 32 Rate T-1 - 38 38 - 397,887 397,887 - 14.0 14.0 33 Rate T-2 - 27 27 - 5,069,101 5,069,101 - 82.4 82.4 34 Rate T-3 - 1 1 - 255,245 255,245 - 7.6 7.6 35 Rate M5 4 31 35 1,767 57,200 58,966 0.6 2.5 3.1 36 Rate 25 29 22 51 54,615 201,050 255,665 12.8 7.1 19.9 37 Rate 30 - - - - - - - - - 38 Total Union Rate Zones 64 454 518 136,098 9,252,076 9,388,174 36.5 220.9 257.4
39 Total Contract Sales 165 942 1,107 407,052 12,296,407 12,703,459 104.5 307.5 412.0
40 Subtotal 3,806,749 94,772 3,901,521 12,817,046 15,307,248 28,124,294 5,043.5 596.6 5,640.1
41 Accounting Adjustments:
42 EGI Tax Variance (27.2) 43 EGI Accounting Policy Change (40.3) 44 EGD Average Use / Normalized Average Consumption 16.9 45 EGD Dawn Access COS (DACDA)- 46 EGD Incremental Capital Module 4.1 47 EGD LRAM (0.0) 48 EGD Febderal Carbon Program 0.9 49 EGI Greenhouse Gas Emissions Administration 0.1 50 EGD Transactional Services Revenue 12.0 51 Union Average Use / Normalized Average Consumption (3.7) 52 Union Incremental Capital Module 1.8 53 Union Capital Pass-through (1.7) 54 Union Parkway Obligation (0.0) 55 Union LRAM 0.5 56 Union DSM 1.4 57 Union Federal Carbon Program 2.3 58 Elimination of the UGL rate zone unregulated storage cost from EGD rate zone revenues (17.3) 59 Miscellaneous 11.9
60 Total Utility Revenue 5,601.7
(103M3)($ Millions)
Weather Normalized Customer Meters, Volumes and Revenues by Rate ClassEnbridge Gas Inc.
For the Year Ending December 31, 2023
Throughput Volumes Revenues
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 2
Schedule 2 Page 2 of 4
Page 148
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8 Col. 9
LineNo.Sales T-Service Total Sales T-Service Total Sales T-Service Total
1 General Service2Rate 1 2,094,144 30,288 2,124,432 5,029,401 76,913 5,106,314 2,358.5 17.6 2,376.1 3 Rate 6 148,947 21,213 170,160 3,031,974 1,755,703 4,787,677 1,145.4 163.9 1,309.4 4 Rate 9 0 0 0 (1) 0 (1) (0.0) 0 (0.0) 5 Total EGD Rate Zone 2,243,091 51,501 2,294,592 8,061,374 1,832,617 9,893,991 3,504.0 181.5 3,685.5
6 Rate M1 1,155,352 29,101 1,184,453 2,992,122 191,540 3,183,662 1,232.6 20.1 1,252.8 7 Rate M2 4,546 3,424 7,970 563,032 663,196 1,226,228 180.3 42.9 223.2 8 Rate 01 355,311 9,881 365,192 944,713 66,223 1,010,936 487.1 14.4 501.5 9 Rate 10 1,356 857 2,213 146,808 173,648 320,456 58.5 22.7 81.3 10 Total Union Rate Zones 1,516,565 43,263 1,559,828 4,646,675 1,094,606 5,741,281 1,958.6 100.2 2,058.8
11 Total General Service 3,759,656 94,764 3,854,420 12,708,049 2,927,223 15,635,272 5,462.5 281.7 5,744.2
12 Wholesale - Utility13Rate M9 1 3 4 18,996 77,894 96,890 5.4 1.3 6.7 14 Rate M10 3 0 3 331 0 331 0.1 0 0.1 15 Total Wholesale - Utility 4 3 7 19,326 77,894 97,221 5.5 1.3 6.8
16 Contract Sales17Rate 100 7 11 18 12,929 23,886 36,815 4.3 2.3 6.6 18 Rate 110 81 361 442 114,059 1,083,818 1,197,877 33.8 47.1 80.9 19 Rate 115 2 13 15 1,040 399,955 400,995 0.3 9.8 10.1 20 Rate 125 4 4 977,270 977,270 - 12.2 12.2 21 Rate 135 7 34 41 2,578 56,442 59,020 0.9 1.6 2.5 22 Rate 145 3 15 18 1,302 17,607 18,909 0.4 1.8 2.2 23 Rate 170 8 13 21 7,685 284,279 291,964 2.1 2.7 4.8 24 Rate 200 1 0 1 136,663 50,697 187,361 40.3 2.5 42.8 25 Rate 300 0 2 2 211 211 0 0.1 0.1 26 Rate 315 0 0 0 0 0 0 0 0.0 0.0 27 Total EGD Rate Zone 109 453 562 276,255 2,894,167 3,170,422 82.1 80.2 162.3
28 Rate M4 31 191 222 64,479 537,398 601,877 21.2 30.5 51.7 29 Rate M7 5 60 65 41,088 708,979 750,067 13.7 24.5 38.2 30 Rate 20 5 59 64 9,113 870,231 879,345 4.2 33.8 38.0 31 Rate 100 0 11 11 0 943,946 943,946 0 11.9 11.9 32 Rate T-1 0 38 38 0 440,944 440,944 0 14.3 14.3 33 Rate T-2 0 26 26 0 4,850,508 4,850,508 0 82.1 82.1 34 Rate T-3 0 1 1 0 278,032 278,032 0 7.5 7.5 35 Rate M5 4 33 37 1,835 58,974 60,809 0.7 2.5 3.2 36 Rate 25 40 25 65 68,669 82,612 151,281 21.2 3.7 24.9 37 Rate 30 0 0 0 0 0 0 0 0 038Total Union Rate Zones 85 444 529 185,184 8,771,624 8,956,808 61.0 210.8 271.8
39 Total Contract Sales 194 897 1,091 461,440 11,665,791 12,127,231 143.1 290.9 434.0
40 Subtotal 3,759,854 95,664 3,855,518 13,188,815 14,670,908 27,859,723 5,611.2 573.9 6,185.1
41 Accounting Adjustments:
42 EGI Tax Variance (29.9) 43 EGI Accounting Policy Change (2.8) 44 EGD Average Use / Normalized Average Consumption 6.9 45 EGD Dawn Access COS (DACDA)1.2 46 EGD Incremental Capital Module (6.9) 47 EGD LRAM 0.1 48 EGD Febderal Carbon Program 0.9 49 EGD Greenhouse Gas Emissions Administration 0.1 50 EGD Transactional Services Revenue 12.0 51 Union Average Use / Normalized Average Consumption 8.8 52 Union Incremental Capital Module (2.0) 53 Union Capital Pass-through (2.9) 54 Union Parkway Obligation (0.1) 55 Union LRAM 0.8 56 Union Federal Carbon Program 2.0 57 Elimination of the UGL rate zone unregulated storage cost from EGD rate zone revenues (17.4) 58 Miscellaneous 8.9
59 Total Utility Revenue 6,164.5
(103M3)($ Millions)
Customer Meters, Volumes and Revenues by Rate ClassEnbridge Gas Inc.
For the Year Ending December 31, 2022
Customer Meters Throughput Volumes Revenues
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 2
Schedule 2 Page 3 of 4
Page 149
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8 Col. 9
LineNo.Sales T-Service Total Sales T-Service Total Sales T-Service Total
1 General Service2Rate 1 2,094,144 30,288 2,124,432 4,928,130 76,175 5,004,305 2,332.3 17.4 2,349.7 3 Rate 6 148,947 21,213 170,160 2,954,007 1,737,662 4,691,668 1,128.3 161.6 1,289.9 4 Rate 9 0 0 0 (1) 0 (1) (0.0) 0 (0.0) 5 Total EGD Rate Zone 2,243,091 51,501 2,294,592 7,882,136 1,813,836 9,695,973 3,460.6 179.0 3,639.6
6 Rate M1 1,155,352 29,101 1,184,453 2,975,284 190,462 3,165,746 1,229.4 20.1 1,249.5 7 Rate M2 4,546 3,424 7,970 561,927 661,894 1,223,821 180.2 42.8 223.0 8 Rate 01 355,311 9,881 365,192 940,369 65,918 1,006,288 485.8 14.4 500.2 9 Rate 10 1,356 857 2,213 147,198 174,109 321,307 58.7 22.8 81.5 10 Total Union Rate Zones 1,516,565 43,263 1,559,828 4,624,779 1,092,383 5,717,162 1,954.0 100.1 2,054.1
11 Total General Service 3,759,656 94,764 3,854,420 12,506,915 2,906,220 15,413,135 5,414.6 279.1 5,693.7
12 Wholesale - Utility13Rate M9 1 3 4 18,996 77,894 96,890 5.4 1.3 6.7 14 Rate M10 3 0 3 331 0 331 0.1 0 0.1 15 Total Wholesale - Utility 4 3 7 19,326 77,894 97,221 5.5 1.3 6.8
16 Contract Sales17Rate 100 7 11 18 12,918 23,886 36,804 4.3 2.3 6.6 18 Rate 110 81 361 442 113,896 1,083,182 1,197,078 33.8 47.1 80.9 19 Rate 115 2 13 15 1,036 399,937 400,973 0.3 9.8 10.1 20 Rate 125 0 4 4 - 977,270 977,270 0 12.2 12.2 21 Rate 135 7 34 41 2,578 56,401 58,979 0.9 1.6 2.5 22 Rate 145 3 15 18 1,289 17,581 18,869 0.4 1.8 2.2 23 Rate 170 8 13 21 7,685 283,859 291,544 2.1 2.7 4.8 24 Rate 200 1 0 1 139,960 50,697 190,657 40.3 2.5 42.8 25 Rate 300 0 2 2 0 211 211 0 0.1 0.1 26 Rate 315 0 0 0 0 0 0 0 0.0 0.0 27 Total EGD Rate Zone 109 453 562 279,361 2,893,025 3,172,386 82.1 80.2 162.3
28 Rate M4 31 191 222 64,479 537,398 601,877 21.2 30.5 51.7 29 Rate M7 5 60 65 41,088 708,979 750,067 13.7 24.5 38.2 30 Rate 20 5 59 64 9,113 870,231 879,345 4.2 33.8 38.0 31 Rate 100 0 11 11 0 943,946 943,946 0 11.9 11.9 32 Rate T-1 0 38 38 0 440,944 440,944 0 14.3 14.3 33 Rate T-2 0 26 26 0 4,850,508 4,850,508 0 82.1 82.1 34 Rate T-3 0 1 1 0 278,032 278,032 0 7.5 7.5 35 Rate M5 4 33 37 1,835 58,974 60,809 0.7 2.5 3.2 36 Rate 25 40 25 65 68,669 82,612 151,281 21.2 3.7 24.9 37 Rate 30 0 0 0 0 0 0 0 0 038Total Union Rate Zones 85 444 529 185,184 8,771,624 8,956,808 61.0 210.8 271.8
39 Total Contract Sales 194 897 1,091 464,545 11,664,649 12,129,194 143.1 290.9 434.0
40 Subtotal 3,759,854 95,664 3,855,518 12,990,787 14,648,763 27,639,549 5,563.2 571.3 6,134.5
41 Accounting Adjustments:
42 EGI Tax Variance (29.9) 43 EGI Accounting Policy Change (2.8) 44 EGD Average Use / Normalized Average Consumption 6.9 45 EGD Dawn Access COS (DACDA)1.2 46 EGD Incremental Capital Module (6.9) 47 EGD LRAM 0.1 48 EGD Febderal Carbon Program 0.9 49 EGD Greenhouse Gas Emissions Administration 0.1 50 EGD Transactional Services Revenue 12.0 51 Union Average Use / Normalized Average Consumption 8.8 52 Union Incremental Capital Module (2.0) 53 Union Capital Pass-through (2.9) 54 Union Parkway Obligation (0.1) 55 Union LRAM 0.8 56 Union Federal Carbon Program 2.0 57 Elimination of the UGL rate zone unregulated storage cost from EGD rate zone revenues (17.4) 58 Miscellaneous 8.9
59 Total Utility Revenue 6,114.0
(103M3)($ Millions)
Weather Normalized Customer Meters, Volumes and Revenues by Rate Class
Enbridge Gas Inc.
For the Year Ending December 31, 2022
Customer Meters Throughput Volumes Revenues
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 2
Schedule 2 Page 4 of 4
Page 150
Line 2021 2022 2023
No.Particulars ($000s)Actual Actual Actual
(a) (b) (c)
Revenue from Regulated Storage Services:
1 C1 Off-Peak Storage 433 138 1,046
2 Supplemental Balancing Services 640 1,053 905
3 Gas Loans 1 (1)(1)
4 C1 Short Term Firm Peak Storage 1,536 2,108 2,634
5 Short Term Storage and Balancing Services Deferral 3,577 3,732 2,352
6 Rate 325: Transmission, Compression, & Storage 2,169 2,303 2,174
7 Less: Elimination of charges between EGD and Union rate zones (2,226) (2,344) (2,238)
8 Total Regulated Storage Revenue Net of Deferral 6,130 6,988 6,871
Revenue from Regulated Transportation Services:
9 M12 Transportation 206,637 213,050 216,935
10 M12-X Transportation 21,527 20,769 14,839
11 C1 Long Term Transportation 19,934 21,023 20,013
12 Rate 332: Gas Transmission 18,107 18,313 19,186
13 C1 Short Term Transportation 7,226 8,365 7,024
14 Gross Exchange Revenue 1,729 1,127 636
15 Rate 331: Gas Transmission 165 170 172
16 Rate 401: RNG Injection Service 0 111 521
17 M13 Local Production 157 173 173
18 M16 Transportation 926 986 859
19 M17 transportation 545 511 529
20 S&T:Transportation Carbon Facility Collection 2,692 4,196 5,167
21 Other S&T Revenue 1,440 1,407 1,633
22 Less: Elimination of charges between EGD and Union rate zones (138,489) (144,576) (147,672)
23 Total Regulated Transportation Revenue Net of Deferral 142,597 145,627 140,015
EGI Revenue from Regulated Storage & Transportation of Gas
2023 Actual
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 2
Schedule 3 Page 1 of 1
Page 151
Col. 1 Col. 2
2022 2023
Utility Utility
Line
No.Particulars Revenue Revenue
($Millions) ($Millions)
1 Late Payment Penalties 20.9 23.0
2 Account Opening Charges 9.8 9.3
3 Other Billing Revenue 9.7 11.0
4 Customer Billing Revenue 40.4 43.3
5 Open Bill Revenue 5.4 5.4
6
Distributor Consolidated Billing and Direct
Purchase Administration Charges 2.3 2.2
7 Mid Market Transactions 1.4 1.7
8 CNG Rental Revenue 1.6 2.1
9 Other Operating Revenue 2.6 3.1
10 Total Other Revenue 53.6 57.8
11 Other Income (1)(2.1) 7.1
12 Total Other Revenue and Other Income 51.5 64.9
EGI Utility Other Revenue and Other Income
2023 Actuals
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 2
Schedule 4 Page 1 of 1
Page 152
Filed: 2024-05-31 EB-2024-0125 Exhibit B
Tab 3
Schedule 1 Plus Appendix Page 1 of 5
UTILITY OPERATING AND MAINTENANCE
1. This evidence explains the drivers in the Utility Operating and Maintenance (O&M)
expense change from 2022 to 2023.
2. The Utility O&M schedule for 2023 preserves the presentation from the 2022 ESM
Proceeding (EB-2023-0110) to provide transparency to all expense categories and
in particular, segregating Corporate Shared Services (CSS), Demand Side
Management (DSM), and Integration-related costs. The Company recognizes that
this O&M presentation is useful to inform stakeholders about operating costs, and as
such, has maintained the presentation to allow the driver explanations to be
comparable between years.
3. Table 1 presents 2023 O&M expenses relative to the prior year. Appendix A is
provided as required and agreed to by Enbridge Gas. As in 2022, Enbridge Gas
provided an appendix reconciling 2023 O&M results presented in the format of
Table 1 compared to formats previous to 2019. This appendix is only provided to
satisfy a previous commitment and is not used for any internal analysis or other
purposes.
4. Overall, O&M expenses increased by $106.5 million primarily due to higher
Miscellaneous Expense, Compensation and Benefits, DSM, Materials and Supplies.
These increases were partially offset by decreases primarily in CSS, integration
related costs and increased Allocations and Recoveries as well as capitalization
recovery on Non-CSS.
Page 153
Filed: 2024-05-31 EB-2024-0125 Exhibit B
Tab 3
Schedule 1 Plus Appendix Page 2 of 5
Table 1
Utility O&M
2022-2023 Actuals
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5
2022 2023
Actual Actual Line No. Expense Categories ($M) ($M) $ change % change
1 Compensation and Benefits 398.9 425.9 26.9 6.8%
2 Employee Related Services and Development 2.1 2.2 0.2 8.2%
3 Materials and Supplies 31.7 37.1 5.4 16.9%
4 Outside Services 271.3 270.6 (0.6) -0.2%
5 Transportation Related Repairs and Maintenance 7.4 9.7 2.3 30.6%
6 Vehicle Related Repairs and Maintenance 19.9 22.8 2.9 14.5%
7 Rents and Leases 12.6 12.2 (0.4) -3.4%
8 Telecommunications 0.2 0.1 (0.1) -53.2%
9 Travel and Entertainment 8.1 8.9 0.8 9.9%
10 Donations and Memberships 3.6 5.4 1.7 46.8%
11 Admin Expenses 2.9 2.4 (0.5) -18.4%
12 Allocations & Recoveries (12.1) (17.8) (5.6) 46.4%
13 Corporate Shared Services (CSS) 285.2 273.8 (11.5) -4.0%
14 DSM 132.1 142.3 10.2 7.7%
15 Integration-Related Costs 30.8 17.2 (13.8) -44.7%
16 Miscellaneous Expense 16.4 299.8 283.4 1729.7%
17 Capitalization on Non-CSS (183.1) (209.4) (26.3) 14.4%
18 O&M Subtotal before Eliminations 1028.1 1,303.2 275.1 26.8%
19 Donations (1.1) (2.5) (1.4) 122.0%
20 CDM Program 0.0 - 0.0
21 ABC T-service Program (0.3) (0.3) (0.0) 2.3%
22 CF utility adjustment (8.4) (11.2) (2.8)
23 Other Eliminations (0.3) 0.3 -100.0%
24 Unregulated Adjustments (15.6) (24.2) (8.6) 54.7%
25 Pension Impairment Eliminations (156.1) (156.1) 0.0%
26 Total Unregulated/Non-Utility Eliminations (25.8) (194.3) (168.6) 48.4%
27
Total Net Utility O&M Expense
1002.3 1108.8 106.5 26.2%
Page 154
Filed: 2024-05-31 EB-2024-0125 Exhibit B
Tab 3
Schedule 1 Plus Appendix Page 3 of 5 5. Miscellaneous Expense (Line 16) increased $283.4 million over the prior year
primarily due to impairment charges related to the OEB Settlement and Phase 1
rebasing decisions driven by the pension balance write-off ($156.1 million), write-off
of net capital integration costs ($84.3 million), and GTA/WAMS capital write-offs
($41.0 million). The pension write-off of $156.1 million is considered non-utility cost
and is eliminated on Line 25.
6. Corporate Shared Services (CSS) costs (Line 13) include business functions such
as Legal, Finance, Human Resources and Technology Information Services (TIS)
that serve business units across the Enbridge enterprise. Costs are charged to the
individual business units based on appropriate cost allocation in relation to the
services received.
7. CSS costs were $11.5 million lower than the prior year primarily due to: lower CSS
benefits and higher CSS capitalization partially offset by higher CSS allocations.
8. Compensations and Benefits (Line 1) increased by $26.9 million over the prior year
from an $11.0 million increase in merit. An increase of $5.3 million was driven by
higher Operations and Customer Care FTEs. The increased Operations FTEs were
to address COVID-19 induced labour shortages, and reflect requirements for the
transition to pre COVID-19 work volume. An increase in Customer Care FTEs were
required to increase focus on meeting SQR targets. In addition, the business unit
benefits increased by $9 million due to higher FTEs and higher pension expense.
9. The Company’s multi-year DSM Plan Application was filed with the OEB on May 3,
2021, and is designed to make homes and businesses more energy efficient, help
lower average annual gas usage, and help meet Ontario’s GHG reduction goals.
The $10.2 million increase in DSM (Line 14) are a pass-through component of utility
O&M and are included in total recoverable amounts although part of a separate
proceeding.
Page 155
Filed: 2024-05-31 EB-2024-0125 Exhibit B
Tab 3
Schedule 1 Plus Appendix Page 4 of 5 10. Materials and Supplies (Line 3) increased $5.4 million over the prior year primarily
due to inflation, increased spend on integrity management programs and additional
purchase of odourant.
11. Allocation and Recoveries (Line 12) increased by $5.6 million driving lower O&M due
to higher direct charges to capital projects in Operations and Engineering and offset
by higher allocation charges to the unregulated business. All unregulated business
costs are removed in unregulated adjustments (Line 24).
12. Integration-related costs (Line 15) decreased by $13.8 million as integration
initiatives winded down and ended with 2023 being the final year of integration.
13. Unregulated Adjustments (Line 24) increased by $8.5 million driving lower O&M due
to incremental unregulated costs primarily related to Enbridge RNG projects,
Enbridge Sustain, and the Carbon Capture project.
1. 2023 Overhead Capitalization
14. The following section describes total overhead capitalization for both CSS (included
in Line 13) and non-CSS cost categories (Line 17).
15. Overhead capitalization applies to all expense categories except integration-related
costs, which are fully expensed. Total combined overhead capitalization was $35.3
million more than the prior year (Table 2).
16. Non-CSS overhead capitalization increased by $26.3 million driven by the increases
in O&M expenses noted in the previous section.
17. CSS overhead capitalization increased by $9.0 million from the prior year driven by
the increases in CSS capitalization rate and loading rate from the annual update to
the overhead capitalization methodology.
Page 156
Filed: 2024-05-31 EB-2024-0125 Exhibit B
Tab 3
Schedule 1 Plus Appendix Page 5 of 5
Table 2
Total Overhead Capitalization Impact on O&M
2022 2023 2023-2022
Actual Actual Variance
Line No. Categories ($M) ($M) ($M)
1 CSS-related Capitalization (86.7) (95.7) (9.0)
2 Capitalization on Non-CSS (183.1) (209.4) (26.3)
3 Total Overhead Capitalization (269.7) (305.0) (35.3)
18. Table 3 summarizes the Total Corporate allocation, the CSS capitalization applied,
and Total Net CSS. Variance explanations are as noted in previous sections.
Table 3
CF Cost Allocations and CSS
Line No. Categories 2022 2023
2022-2023 Variance
1 CF Cost Allocations 371.9 369.4 (2.5)
2 Less: Utility adjustment (8.4) (11.2) (2.8)
3 Utility CF cost Allocations 363.5 358.2 (5.3)
4 Less: Capitalization of CSS (86.7) (95.7) (9.0)
5 Net Utility CSS 276.8 262.6 (14.3)
Page 157
Col. 1Col. 2 Col. 3Col. 4 Col. 5Col. 6Col. 7Col. 8 Col. 9 Col. 10 Col. 112022 ACTUAL2023 ACTUAL2022-2023 2022-2023Line No. Expense Categories ($M)2022Previous FormatCentral Functions CostsDSM & Integration Costs2022Revised2023Previous FormatCentral Functions CostsDSM & Integration Costs2023Revised$ change% change1 Compensation and Benefits493.8(69.6) (25.3) 398.9519.1(72.2) (20.9) 425.927.06.8%2 Employee Related Services and Development6.2(3.3)(0.8)2.17.5(5.1) (0.2) 2.20.28.2%3 Materials and Supplies52.2(1.7) (18.8)31.766.3(2.2) (27.0) 37.15.416.9%4 Outside Services440.0(50.8) (117.9) 271.3452.0(71.0) (110.3) 270.6(0.6)-0.2%5 Transportation Related Repairs and Maintenance9.4(2.0)(0.0)7.49.7(0.1) (0.0) 9.72.330.6%6 Vehicle Related Repairs and Maintenance20.0(0.0)(0.0)19.922.9(0.0) (0.0) 22.82.914.5%7 Rents and Leases14.9(2.3)0.012.615.1(2.9) - 12.2(0.4)-3.4%8 Telecommunications0.20.0(0.0)0.20.2(0.1) (0.0) 0.1(0.1)-53.2%9 Travel and Entertainment9.6(1.0)(0.6)8.111.3(1.3) (1.1) 8.90.89.9%10 Donations and Memberships4.7(0.3)(0.8)3.65.20.7 (0.5) 5.41.849.6%11 Admin Expenses0.0(0.2)3.12.9(0.3)0.1 2.5 2.4(0.5)-18.4%12 Allocations & Recoveries230.6(242.2)(0.5) (12.1)199.4(216.6) (0.6) (17.8)(5.6)46.4%13 Corporate Shared Services (CSS)0.0285.2285.20.0275.1 (1.3) 273.8(11.5)-4.0%14 DSM0.0132.1132.10.0- 142.3 142.310.27.7%15 Integration-Related Costs(0.0)1.329.530.80.0- 17.2 17.2(13.7)-44.3%16 Miscellaneous O&M Expense16.20.116.4299.8(0.0) 299.8283.41729.7%17 Capitalization on non-CSS(269.7)86.7(183.1)(305.0)95.7 (209.4)(26.3)14.4%18 O&M Subtotal before Eliminations1028.1(0.0)0.0 1028.11303.20.0(0.0) 1303.2275.226.8%19 Donations(1.1)(1.1)(2.5)(2.5)(1.4)122.0%20 CDM Program0.00.00.00.00.021 ABC T-service Program(0.3)(0.3)(0.3)(0.3)(0.0)2.3%22 CF utility adjustment(8.4)(8.4)(11.2)(11.2)(2.8)32.9%23 Other Eliminations(0.3)(0.3)0.00.00.3-100.0%24 Unregulated Adjustments(15.6)(15.6)(24.2)(24.2)(8.6)54.7%25 Pension Impairment Eliminations(156.1)(156.1)(156.1)26 Total Unregulated/Non-Utility Eliminations(25.8)(25.8)(194.3)(194.3)(168.6)654.3%27 Total Net Utility O&M Expense1002.31002.31108.81108.8 106.5 10.6%Table 1Reconciliation of Utility O&M Schedule2022 & 2023 ResultsFiled: 2024-05-31 EB-2024-0125 Exhibit B Tab 3 Schedule 1 Appendix A Page 1 of 1Page 158
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 1 of 11
UTILITY CAPITAL EXPENDITURES
1. The purpose of this evidence is to provide information on Enbridge Gas’ 2023 utility
capital expenditures within the EGD and Union rate zones.
Table 1
Summary of Capital Expenditures 2023 Actual
($millions)
Col 1 Col 2 Col 3
Line
No.
Particulars
EGD UG Total EGI
1 Distribution Plant 473.1 399.4 872.5
2 Transmission Plant - 101.9 101.9
3 General & Other Plant 115.5 15.3 130.8
4 Underground Storage Plant 324.7 13.0 337.8
5 Total 913.4 529.6 1,442.9
2. The dollars presented are annual capital expenditures and are comparable to the
presentation in the Asset Management Plan. Capital expenditures in ICM
applications are presented on an in-service basis.
3. Tables 2 and 3 show the regulated expenditures by Asset Class for each of the rate
zones. Further commentary regarding the year over year changes in capital
expenditures are described by Asset Class in the narrative following Tables 2 and 3.
Page 159
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 2 of 11
Table 2
EGD Rate Zone by Asset Class
($millions)
Line
No.
Asset Class
2022 2023 Variance
1 Compression Stations 73.4 314.0 240.6
2 Customer Connections 183.8 210.3 26.5
3 Distribution Pipe 205.2 110.5 (94.7)
4 Distribution Stations 54.8 25.4 (29.4)
5 Fleet & Equipment 15.0 6.4 (8.6)
6 Growth - Distribution System Reinforcement 10.2 9.4 (0.8)
7 Real Estate & Workplace Services 46.5 62.9 16.4
8 Technology Information Services (TIS) 18.2 39.1 21.0
9 Transmission Pipe and Underground Storage 9.1 10.8 1.7
10 Utilization 44.6 87.3 42.6
11 EA Fixed Overhead 22.2 19.3 (2.9)
12 Capitalized Overheads - - -
13 Integration Capital 24.0 7.0 (17.0)
14 Community Expansion 9.3 8.1 (1.3)
15 Other 1.6 2.9 1.3
16 Total 718.0 913.5 195.5
Table 3
UG Rate Zone by Asset Class
($millions)
Line
No.
Asset Class
2022 2023 Variance
1 Compression Stations 33.4 16.5 (16.9)
2 Customer Connections 113.2 131.6 18.4
3 Distribution Pipe 272.3 138.4 (133.9)
4 Distribution Stations 42.3 25.0 (17.3)
5 Fleet & Equipment 15.5 4.6 (10.9)
6 Growth - Distribution System Reinforcement 59.2 28.0 (31.2)
7 Real Estate & Workplace Services 17.9 10.1 (7.8)
8 Technology Information Services (TIS) 9.9 8.2 (1.7)
9 Transmission Pipe and Underground Storage 87.7 74.4 (13.3)
10 Utilization 53.7 84.5 30.8
11 EA Fixed Overhead 4.8 3.2 (1.6)
12 Capitalized Overheads - - -
13 Integration Capital 4.7 1.5 (3.2)
14 Community Expansion 4.9 1.9 (3.0)
15 Other (0.5) 1.5 2.0
16 Total 719.1 529.5 (189.6)
Page 160
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 3 of 11
1. Descriptions of Asset Classes and Year over Year Variances
4. Effective January 2021, Enbridge Gas is allocating capitalized overheads to projects
based on the total pool of overheads and the total direct capital spend by rate zone.
As a result, capitalized overheads are being reflected within the asset classes and
will no longer be shown as a separate asset class. This is consistent with the
presentation of overheads in the Asset Management Plan and ICM applications (as
of 2021).
a) Compression Stations
Enbridge Gas (Union rate zone) uses compressors to move natural gas
throughout the natural gas transmission system by compressing natural
gas into transmission pipelines designed for high pressure and flow.
Compressors are also used for both rate zones to move gas in and out of
underground storage reservoirs by providing a significant pressure
increase at the expense of flow.
Dehydration facilities are also included in the compression asset category.
Dehydration facilities remove moisture from natural gas to ensure that the
natural gas entering the transmission system meets the contractual
standard of moisture content, and to avoid operational problems related to
high moisture content. Enbridge Gas operates one liquified natural gas
(LNG) facility, the LNG facility serves to provide reserve capacity and
balance operational loads during peak periods.
The EGD rate zone increased primarily due to the continuation of the
Dawn to Corunna Replacement project ($266 million).
b) Customer Connections
This asset class includes the addition of new customers based on new
housing or business starts, customers converting to natural gas from
another fuel source and equipment and service upgrades to accommodate
load growth of existing customers. General customer growth costs include
Page 161
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 4 of 11
materials and installation of mains and services to attach new customers
as well as the costs associated with the meter and regulator installation at
the customers site.
For both rate zones, there was an increase in customer connections in
2023 compared to 2022. In addition, the average cost for customer
connection increased for both rate zones due to the inflation pressures for
labor and materials.
c) Distribution Pipe
This asset class includes the maintenance, replacement, and renewal of
pipelines and piping components (such as valves and fittings) used to
transport natural gas within the distribution system or to end-use
customers. It includes steel and plastic pipe, as well as services to
customers.
The EGD rate zone decreased in 2023 due to significant capital allocated
to the completion of NPS 20 Lake Shore Replacement Cherry to Bathurst
project in 2022 and less Integrity spend in 2023 compared to 2022.
The Union rate zone decreased due to the completion of projects
executed in 2022 including the London Lines project ($32.1 million) and
the Kirkland Lake Lateral project ($26 million) combined with less Integrity
spend in 2023 compared to 2022.
d) Distribution Stations
These assets are typically above grade facilities designed to reduce the
operating pressure of natural gas pipeline systems through pressure
control and over pressure protection. These facilities are used to transmit
and/or distribute natural gas to reduced operating pressure pipeline
systems which supply natural gas to cities and towns.
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EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 5 of 11
The EGD rate zone decreased due to completion of Brampton Gate
Rebuild ($9.6 million), Dale Gate Rebuild ($5.8 million) and Martin Grove
Feeder ($4.3 million).
The Union rate zone decreased due to the pacing of station replacements
and rebuilds including Leamington North Gate ($5.7 million) and others to
offset inflationary pressures for labor and materials in other asset classes.
e) Fleet & Equipment
The Fleet, Equipment and Tools asset class includes the vehicles, trailers,
heavy equipment and tools owned by Enbridge Gas to support its
business needs.
Decreases in the Fleet, Equipment and Tools asset class across both rate
zones, between 2023 and 2022, are attributed to expenditure reductions
in Tools ($5.9 million) and Vehicles and Equipment ($15.3 million).
f) Growth – Distribution System Reinforcement
The Growth asset class includes reinforcements driven by customer and
load growth.
The EGD rate zone had little variance year over year.
The Union rate zone decreased due to the completion of a number of
reinforcement projects executed in 2022: Ingersoll Transmission Station
($10.6 million), Byron Transmission Station ($8.9 million), Greenstone
Mine ($5.7 million), and Staples Reinforcement ($4.0 million).
g) Real Estate and Workplace Services
The Real Estate and Workplace Services (REWS) asset class includes
properties (buildings and land) and furnishings.
There is a base spend for each rate zone that supports building repairs
and acquisition of furnishings. Variances are driven by the specific land
purchases and building renovations that occur in a given year. Land
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EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 6 of 11
acquisitions are driven by market availability and are aligned with the long-
term strategies described in the Asset Management Plan.
The EGD rate zone increased due to the execution of the Ottawa Building
($27.0 million).
The Union rate zone decreased due to the pacing of Chatham Building
renovation located at 50 Keil to offset the inflationary pressures for labor
and materials in other asset classes.
h) Technology Information Services
The Technology Information Services (TIS) asset class includes:
o General Hardware (Laptops/Desktops and Desktop sustainment
equipment, networks, servers and security);
o Specialized Hardware (to support specific business needs such as
meter reading equipment, call center network devices);
o Software assets consisting of packaged applications, developed
applications, and application infrastructure software; and
o Communications assets including mobile phones and field devices
(such as GPS devices, push-to-talk radios, leak survey field
technology, and truck modems).
The EGD rate zone increases were largely due to the start of Contract
Market Modernization project ($18.1 million) in 2023. The Union rate zone
did not experience a significant variance from 2022 to 2023.
i) Transmission Pipe and Underground Storage
This asset class includes the pipelines that form the backbone of the gas
transmission system as well as the underground storage reservoirs in St.
Clair Township near Sarnia, Crowland Township in Welland, and in
Chatham-Kent.
EGD rate zone did not experience a significant variance from 2022 to
2023. The UG rate zone decreased due to the completion of Dawn to
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EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 7 of 11
Cuthbert NPS 42 Replacement ($17.1 million) combined with less integrity
spend ($6.4 million) which was offset by the increase in the Panhandle
Regional Expansion Project ($17.2 million).
j) Utilization
The utilization asset class includes measurement & regulation systems at
customer premises, below ground and internal piping systems after the
meter, and customer-owned systems1.
Both rate zones increased to align pacing with the integrated policy for
Government Inspection Program. In addition, both rate zones' labor and
material costs increased for Meter Exchanges due to material shortages
and inflation.
k) EA Fixed Overheads
The EA fixed overhead asset class includes cost for Alliance partner
overheads and district contractor pre-work costs. The decrease in the
EGD rate zone is due to a one-time fuel surcharge in 2022. The decrease
in the Union rate zone is due to the timing of payments.
l) Capitalized Overheads
As set out above, effective January 2021, Enbridge Gas is allocating
capitalized overheads to projects based on the total pool of overheads and
the total direct capital spend by rate zone. As a result, capitalized
overheads are being reflected within the asset classes and are no longer
shown as a separate asset class. This is consistent with the presentation
of overheads in the Asset Management Plan and ICM applications (as of
2021).
1 For customer owned systems that are downstream of the meter, the asset class is accountable for
inspection at the time of initial installation and after re-introduction of gas. Maintenance and remediation
of these assets are the responsibility of the customer.
Page 165
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 8 of 11
Total combined capitalized overheads increased by $38.3 million which
includes a $4.2M increase to IDC as a result of increases to the OEB
prescribed rate. The indirect overhead increases of $34.1 million are
explained in Exhibit B, Tab 3, Schedule 1.
m) Integration Capital
Integration capital included expenditures required to integrate the two
legacy companies. Enbridge Gas evaluated projects to determine if they
met the criteria of integration capital: a one time incremental cost related
to the amalgamation of the legacy utilities. Projects were identified to
address integration needs, or they were driven by a need to replace an
asset due to obsolescence. In either case, the project was classified as
integration as it drove a harmonized solution that added value to the
integrated utility. These expenditures were excluded when calculating the
thresholds for ICM capital.
The decrease in both the EGD and UG rate zones are due to higher
spend for Cost of Gas and Asset and Work Management System in 2022
and write-off of completed projects in 2023, as a result of the OEB’s 2024
Phase 1 Rebasing Decision2.
n) Community Expansion
Community expansion provides natural gas services to communities not
currently using natural gas. In response to the Government of Ontario’s
desire to expand natural gas distribution systems to communities that
currently do not have access to natural gas, Enbridge Gas has filed
proposals with the OEB designed to facilitate enhanced access to natural
gas for non-served rural, remote and First Nation communities, and
businesses in Ontario.
2 EB-2022-0200, OEB Decision and Order, December 21, 2023, p. 74.
Page 166
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 9 of 11
In the EGD rate zone, the decrease in spend is primarily related to lower
spend on the Scugog Island project due to construction completion, offset
by the start of design work for the Community Expansion Phase 2
projects.
In the Union rate zone, the decrease is due to higher contributions
recognized for the Community Expansion Phase 2 projects.
5. Tables 4 and 5 show the Asset Classes with storage spend for each rate zone and
the allocation of costs between the regulated and unregulated segments of Enbridge
Gas’s storage operations. Both the EGD and Union rate zones have OEB approved
policies and methodologies for unregulated storage allocations. Allocations are
maintained at the individual asset level and updated annually to reflect additions and
retirements to the assets. The allocations are applied to storage based capital
projects in order to separate the regulated and unregulated costs. Regulated
projects include indirect overhead allocations.
Table 4
EGD Rate Zone Storage by Asset Class 2023 Actual
($millions)
Line
No. Asset Class
Regulated Unregulated
1 Compression Stations 313.9 (0.5)
2 Transmission Pipe and Underground Storage 10.8 6.2
3 Total Capital Expenditures 324.7 5.7
6. EGD Rate Zone Compression Stations – significant projects related to EGD’s
regulated assets include Dawn to Corunna Replacement ($303.2 million),
SCOR:60004-Fdn-Blk-Replace ($3.0 million), SSOM:K-802 Iso Valves-Replace
($1.1 million), SSOM: V-0805 Iso Valves - Rep ($1.0 million) and SCOR:61008Top
End-O/H ($1.0 million).
Page 167
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 10 of 11
7. EGD Rate Zone Transmission Pipe and Underground Storage – significant projects
related to EGD’s regulated assets include NPS 16 Wilkesport P and C ($2.9 million),
NPS 16 WLK Trans Retrofit ($1.8 million), PCRW:Wells-Upgrade ($1.5 million) and
NPS 20 SK Loop P&C ($1.0 million) and Dow Moore MOP Remediation ($1.0
million). Significant unregulated projects include TPS-Wells SE24 PMKC ($1.7
million), LLAD: Pipeline and Meter Station ($1.4 million) and SE 21/22 LDOW ($1.2
million) and PLAD:TL8 A1 Obs Well-Drill ($1.1 million) which will increase the
maximum operating pressure of the Corunna and Ladysmith pools. The Storage
Enhancement projects are being executed in 2 phases in order to meet the growing
market demand for incremental storage space.
Table 5
UG Rate Zone Storage by Asset Class 2023 Actual
($millions)
Line
No. Asset Class
Regulated Unregulated
1 Compression Stations
16.6
6.8
2 Transmission Pipe and Underground Storage
74.4
2.7
3 Total Capital Expenditures
91.0
9.5
8. UG Rate Zone Compression Stations – significant projects related to UG’s regulated
assets include Dawn:5985 CV Piping & Improvements ($3.3 million), STO Convert
High Bleed devices to Low/no bleed ($2.1 million) and Bright B PLC Upgrade ($1.2
million). Unregulated projects include the Dawn Dehy Plant – Process Tank
Replacement ($5.9 million) and Dawn I Plant Glycol Line Replacement ($0.9 million).
9. UG Rate Zone Transmission Pipe and Underground Storage – significant projects
related to UG’s regulated assets include the Panhandle Regional Expansion Project
($50.1 million), Trafalgar NPS 26 Integrity Digs ($7.4million), Panhandle NPS 20 AC
Mitigation ($4.9 million), Dawn-Cuthbert – NPS 42 replacement ($1.1 million),
Page 168
Filed: 2024-05-31
EB-2024-0125
Exhibit B
Tab 3
Schedule 2
Page 11 of 11
Trafalgar NPS 26 Line Lowering ($1.9 million) and NPS 20 Bickford Sombra IFK
Repairs ($1.0 million). The SE21/22-NPS24/TIE IN/STN , Mandaumin A1
observation well and Bluewater A1 Well($2.7million) are unregulated projects and
part of the 2nd phase of the Storage Enhancement project (EB-2021-0079)
described in paragraph 7.
Page 169
Col. 1Col. 2Col. 3 Col. 4Col. 5Col. 6Col. 7Col 8 Col. 9 Col. 10 Col. 11UCC atTrue-upUCC At Total Additions Less: Lessor Eligible DepreciableLinePrior Year Filing from FilingBeginningQualifying for of Cost orCCAUCC Rate CCAEndingNo. Particulars ($000s)EB-2023-0092 to Tax Returnof Year Total Additions Accel. CCA Proceeds Additions** Balance (%) FY2023UCC(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)Class1 1 Buildings, structures and improvements, services, meters, mains 2,118,476.9 - 2,118,476.9- - -- 2,118,476.9 4% 84,739.1 2,033,737.8 2 1 Non-residential building acquired after March 19, 2007153,170.0 112.7153,282.73,236.8 3,236.8 -4,855.3158,138.0 6%9,488.3 147,031.3 3 2 Mains acquired before 1988143,339.5 - 143,339.5- - --143,339.5 6%8,600.4 134,739.2 4 3 Buildings acquired before 19882,704.7 - 2,704.7- - --2,704.7 5%135.2 2,569.4 5 6 Other buildings63.4 - 63.4- - --63.410%6.357.16 7 Compression equipment acquired after February 22, 2005371,124.6 - 371,124.64,446.1 4,446.1 -6,669.2377,793.8 15% 56,669.1 318,901.6 7 8 Compression assets, office furniture, equipment200,767.9 (6,970.9) 193,797.0 125,909.3 125,909.3 -188,864.0382,661.0 20% 76,532.2 243,174.1 8 10 Transportation, computer equipment30,593.4 (512.6) 30,080.73,253.9 3,253.9 -4,880.934,961.7 30% 10,488.5 22,846.2 9 12 Computer software, small tools780.1 (221.8) 558.433,766.4 33,766.4 -33,766.434,324.7 100% 34,324.7 - 1013 Leasehold improvements139.6 - 139.6- - --139.6 0%107.8 31.911 14.1 Intangibles12,826.0 0.012,826.0564.0 564.0 -846.013,672.0 5%683.6 12,706.4 12 14.1 Intangibles (pre 2017)40,458.5 - 40,458.5- - --40,458.5 7%2,832.1 37,626.4 13 17 Roads, sidewalk, parking lot or storage areas425.4 - 425.4- - --425.4 8%34.0 391.4 14 38 Heavy work equipment11,178.4 (168.0) 11,010.42,462.7 2,462.7 -3,694.114,704.5 30% 4,411.3 9,061.8 15 41 Storage assets81,607.6 (653.0) 80,954.698,405.5 98,405.5 -147,608.3228,562.9 25% 57,140.7 122,219.4 16 45 Computers - Hardware acquired after March 22, 20041.9 - 1.9- - --1.945%0.91.017 49 Transmission pipeline additions acquired after February 23, 2005755,358.0 142.4755,500.4 25,124.4 25,124.4 -37,686.6793,187.0 8% 63,455.0 717,169.9 18 50 Computers hardware acquired after March 18, 20076,966.8 (691.9) 6,274.917,057.2 17,057.2 -25,585.731,860.6 55% 17,523.3 5,808.7 19 51 Distribution pipelines acquired after March 18, 20076,201,229.7 (31,916.7) 6,169,313.0 908,359.9 908,359.9 (4,738.9) 1,360,170.47,524,744.5 6% 451,484.7 6,621,449.3 20 Total10,131,212.4 (40,879.7) 10,090,332.7 1,222,586.3 1,222,586.3 (4,738.9) 1,814,626.8 11,900,220.5 878,657.1 10,429,522.9 Enbridge Gas Inc.Summary of Capital Cost Allowance (CCA)Filed: 2024-05-31 EB-2024-0125 Exhibit B Tab 3 Schedule 3 Page 1 of 1Page 170
ACCOUNTS NOT BEING REQUESTED FOR CLEARANCE
1.The following accounts of Enbridge Gas have zero balances and are therefore not
requested for clearance:
•Earnings Sharing Mechanism Deferral Account – EGI
•Green Button Initiative Deferral Account – EGI
•Cloud Computing Implementation Costs Deferral Account – EGI
•Expansion of Natural Gas Distribution Systems Variance Account – EGI
•Impacts Arising from the COVID-19 Emergency Deferral Account - EGI
2.With respect to the Impacts Arising from the COVID-19 Emergency Deferral
Account, Enbridge Gas was approved to clear the balance as part of the OEB’s
EB-2022-0200 Interim Rate Order, and therefore, Enbridge Gas has no further
balance to dispose of in this proceeding.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 1 of 28
Page 171
ENBRIDGE GAS – ACCOUNTING POLICY CHANGES DEFERRAL ACCOUNT
(APCDA) (No. 179-381)
1.On August 30, 2018, the OEB issued its Decision and Order for the amalgamation
and rate setting mechanism (the MAADs Decision) approving the amalgamation of
Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union) and the rate-
setting framework1. In its Decision, the OEB established a deferral account to record
the impact of any accounting changes required as a result of amalgamation that
affect the revenue requirement.2 The OEB approved wording of the accounting order
for the Accounting Policy Changes Deferral Account (APCDA) effective January 1,
2019 in its Decision and Order on Enbridge Gas’ 2019 Rates application3.
2.In the EB-2022-0200 Phase 1 Decision and Order dated December 21, 2023, the
OEB approved the clearance of deferral and variance accounts as proposed by
Enbridge Gas including the balance in the APCDA, with the exception of the former
Union Gas pre-2017 amortized actuarial gains/losses4. The balance approved within
that application was comprised of actual & forecast amounts. Within this application,
Enbridge Gas is seeking final disposition of the remaining balance in the APCDA,
reflecting the variance between the forecast balance approved in the
EB-2022-0200 Phase 1 Decision and Order, and associated Interim Rate Order
dated April 11, 2024, and the final actual balances calculated through December 31,
2023.
3.The Company tracked the annual revenue requirement impact of accounting policy
changes made as of the amalgamation date, January 1, 2019, or at other points
throughout the deferred rebasing term. The cumulative actual balance of the APCDA
1 EB-2017-0306/0307, MAAD’s Decision and Order dated August 30, 2018; The Decision and Order was
later amended by the OEB on September 17, 2018 with no material changes.
2 EB-2017-0306/0307, MAAD’s Decision and Order dated August 30, 2018, p. 47.
3 EB-2018-0305, 2019 Rates Final Rate Order dated October 24, 2019, Appendix I, p. 7.
4 EB-2022-0200, Decision and Order dated December 23, 2023, pp. 101-107.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 2 of 28
Page 172
as of December 31, 2023 is a credit, or payable of $7.445 million, as compared to
the forecast balance payable of $ 12.956 million which was approved in the
EB-2022-0200 Interim Rate Order. Please refer to Exhibit C, Tab 1, Schedule 2,
Table 1 which categorizes each of the accounting policy changes, provides the
cumulative opening balance as of the beginning of the period, details the current
period revenue requirement impact being added to the cumulative balance, provides
the ending cumulative balance as of the end of the current period, and finally
provides the residual balances being requested as part of this filing. The details of
each item within Table 1 are described further in the remaining evidence presented.
4.Exhibit C, Tab 1, Schedule 2, Table 2 provides an additional detailed breakdown of
the changes by rate zone between what was originally approved through the
EB-2022-0200 Interim Rate Order and the final cumulative balances recorded for
each item. The variance, and amount requested for disposition as part of this
proceeding is a debit (or receivable) of $5.511 million, plus interest of $0.036 million.
5.Please refer to Exhibit C, Tab 1, Schedule 2, Table 3 for the detailed 2023 revenue
requirement calculation of the items presented above.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 3 of 28
Page 173
1.Capitalization vs Expense
6.Capitalization policies differed between EGD and Union with respect to whether the
following items were capitalized or expensed as incurred:
7.Upon amalgamation, it was necessary for Enbridge Gas to align its capitalization
policies where differences existed between legacy EGD and legacy Union. The
policy alignment resulted in a net impact in 2023 between UGL and EGD Rate
Zones of:
•Lower O&M expense of approximately $8.256 million, offset by higher
capitalization; and,
•Gross revenue requirement decrease, or sufficiency of $7.260 million.
8.On a cumulative basis, this policy alignment resulted in a gross revenue requirement
decrease, or sufficiency of $20.319 million, however, the forecast balance approved
for clearance as part of the Rebasing Decision was an $11.666 million sufficiency,
resulting in a residual sufficiency (or credit) balance of $8.653 million that is
proposed for disposition as part of this 2023 ESM Proceeding. The variance results
primarily from a larger amount of integrity dig inspections in the Union Rate Zone
that were capitalized on an actual basis as compared to the forecast.
Union Policy EGD Policy EGI Policy
•Verification of Maximum
Operating PressureProgram (MOP);
•Customer Assets
Programs (Low Pressure
Delivery Meter Set andFarm Tap Programs);
•Distribution Integrity
Technology;
•Distribution RecordsManagement Program;and,
Expensed as
incurred
Capitalized Expensed
as incurred
•Integrity Digs resulting
from integrity inspections
Expensed as
incurred
Capitalized Capitalize
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 4 of 28
Page 174
2.Interest During Construction
9.Interest During Construction (IDC) is a cost of constructing an asset which is
included in the cost of property plant and equipment capitalized.5 IDC is recovered in
rates through depreciation expense, along with a return on rate base over the life of
the asset. Both Union and EGD capitalized IDC in accordance with US GAAP,
however, IDC calculation was different in the legacy utilities, as seen below.
10. Upon amalgamation, it was necessary for Enbridge Gas to align its accounting
treatment of IDC. The policy alignment resulted in the following for 2023:
•Total 2023 net gross revenue requirement decrease, or sufficiency of $1.352
million.
11. On a cumulative basis, this policy alignment resulted in a gross revenue requirement
decrease, or sufficiency of $0.751 million, however, the forecast balance approved
for clearance as part of the Rebasing Decision was a gross revenue requirement
increase, or deficiency of $1.533 million, resulting in a residual sufficiency balance of
$2.284 million that is proposed for disposition as part of this 2023 ESM Proceeding.
The variance results primarily from larger amounts closing into service and a much
larger increase in the OEB prescribed interest rate vs the weighted average cost of
debt rate since Q3 2022 as compared to the forecast.
5 ASC 835-20-05-1.
Union Policy EGD Policy EGI Policy
Threshold IDC is only calculated on projects with capital spend of $1
million or greater, and
that have a duration of greater than 12 months
No threshold – applied to all capital projects regardless of size and
duration
No Threshold – applied to all capital projects regardless of size and
duration
Rate OEB prescribed interest rate for CWIP Weighted average cost of debt (WACD) OEB prescribed interest rate for CWIP
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 5 of 28
Page 175
3.Depreciation Expense
12. Depreciation rates for Union and EGD, in place at the time of amalgamation and
used over the deferred rebasing term, were based on depreciation studies that were
approved by the OEB in prior proceedings.
13.Upon amalgamation, it was necessary for Enbridge Gas to align the depreciation
policies of legacy EGD and legacy Union Gas with respect to how depreciation on
assets is calculated.
14. Since many projects go into service late in the year, the EGD/Enbridge Gas policy
would typically result in a lower first year depreciation expense than following the
Union policy.
15. The policy alignment resulted in an impact in 2023 specific only to the UGL Rate
Zone of:
•A decrease in depreciation expense of approximately $5.427 million; and,
•A gross revenue requirement decrease, or sufficiency of $5.731 million.
16.On a cumulative basis, this policy alignment resulted in a gross revenue requirement
decrease, or sufficiency of $24.190 million, however, the forecast balance approved
for clearance as part of the Rebasing Decision was a gross sufficiency of $31.229
million, resulting in a variance, or balance for recovery, of $7.039 million that is
proposed for disposition as part of this 2023 ESM Proceeding. The variance is a
result of the mix between the amount and timing differences of in-service additions
between actual and forecast. The lower amount of additions in the year and going
Union Policy EGD Policy EGI Policy
Half year of depreciation in the first and last year of service, regardless of month the asset went into
service
Begin depreciation the month after the asset goes into service, and stops the month after retirement
Begin depreciation the month after the asset goes into service, and stops the month after retirement
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 6 of 28
Page 176
into service later result in a smaller gap between Union Rate Zone depreciation on a
half year basis compared to monthly after in-service.
4.Overhead Capitalization
17. Following amalgamation, the Company sought to harmonize its overhead
capitalization methodology and retained Ernst and Young (EY) to carry out the
study. EY’s assessment was informed by historical legacy approaches, the
amalgamated structure, US GAAP, the OEB’s Uniform System of Accounts, and
Enbridge’s Enterprise Capitalization Policy. Recommendations of the study were
implemented in January 2020. The study grouped costs into Operations Costs,
Business Costs, Support Costs, and Pension and Benefits, each with their own
capitalization treatment to more directly link with causal determinants of cost.
18. Prior to this harmonization, capitalized overheads in the legacy EGD approach were
determined by the application of Departmental Labour Costs (DLC) rates and
Administrative & General (A&G) rates to support costs for capital work in field
operations and business support operations, as well as administrative functions that
support the overall business. In legacy UG, annual updates were carried out for
support groups where capitalization rates were derived from time spent on capital
activity.
19. The APCDA isolated the impact of the overhead capitalization policy change. The
calculation took the annual O&M spend with the new harmonized rates and
subtracted from it O&M spend using the legacy rates to determine the APCDA
impact. The policy change resulted in a decrease in O&M and offsetting increase in
capitalized overheads, with the revenue requirement impact recorded in the APCDA.
The net impact in 2023 between UGL and EGD Rate Zones was:
•Lower net OM&A expenses of $22.512 million (offset by higher capitalization
of overheads); and,
•A gross revenue requirement decrease, or sufficiency of $25.450 million
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 7 of 28
Page 177
20. On a cumulative basis, this policy alignment resulted in a gross revenue requirement
decrease, or sufficiency of $24.339 million, however, the forecast balance approved
for clearance as part of the Rebasing Decision was a gross sufficiency of $36.494
million, resulting in a variance in the deficiency balance of $12.155 million that is
proposed for disposition as part of this 2023 ESM Proceeding. The variance is
primarily the result of applying the harmonized capitalization rates to the mix of O&M
spend on an actual basis over 2022 and 2023 that differed from the legacy
approach, resulting in a lower amount of overhead capitalization when compared to
the forecast.
5. Amortized Gas Supply Storage and Transportation Costs
21. As described in Enbridge Gas’ 2024 Rebasing Application6, Enbridge Gas contracts
with third parties for market-based storage and transportation capacity to transport
gas to and from storage. Storage mainly facilitates the load balancing of Enbridge
Gas’s heat-sensitive customer base, but also allows annual transportation contracts
to be utilized more effectively and lowers commodity costs to customers by injecting
lower-priced supply during the summer, which is withdrawn to meet demand during
the winter, when prices for supply are higher. These services are considered a
component of the gas supply portfolio, and costs incurred are recovered through
monthly gas supply rates charged to customers.
22. Enbridge Gas has historically expensed these costs in the EGD rate zone over the
five-month winter period from November 1 to March 31 (which crosses over
Enbridge Gas calendar fiscal years), while similar costs in the Union rate zones are
expensed as incurred over the calendar year. In the EGD rate zone, these monthly
invoiced charges are initially accrued and recognized as a prepaid cost when
invoiced, and accumulated monthly as part of total gas in storage inventory on the
balance sheet. The charges are recorded as gas costs on the income statement
6 EB-2022-0200, Exhibit 9, Tab 2, Schedule 1, pp. 14-16.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 8 of 28
Page 178
over the five-month heating season period, beginning in November and ending in
March, such that at the end of March, the balance in gas in storage inventory is zero.
23. In 2022, Enbridge Gas implemented financial system harmonization for recognition
of gas costs in the general ledger. This system implementation aligned the expense
recognition process for the monthly accrued charges based on calendar year
recognition in line with the approach for the Union rate zones.
24. The accrued balance ($62.155 million) at the end of 2022 in gas in storage
(representing the inventory that would have been amortized from January 1 to March
31 in 2023), was transferred to the APCDA resulting in no amounts being required to
be amortized to gas cost expense in 2023. At the time of the Enbridge Gas
Rebasing filing, the forecast balance for this account was $64.9 million, which was
subsequently approved for clearance. The Company now requests disposition of the
residual sufficiency balance of $2.745 million, the difference between the forecast
amount filed as part of the Rebasing Application and the final balance recorded to
the account, as part of this application.
25. The amount transferred to the APCDA represents costs incurred by Enbridge Gas in
providing service to customers and does not reflect any material change to the total
annual revenue requirement of Enbridge Gas to provide gas supply storage and
transportation service. The change in the accounting treatment does recognize a
one-time transition to allow for consistent recovery of these gas supply storage and
transportation costs for Enbridge Gas.
Union Policy EGD Policy EGI Policy
Costs expensed as
incurred and accrued
monthly over calendar year.
Costs expensed over the
five-month winter period
from November 1 to March 31.
Costs expensed as incurred
and accrued monthly over
calendar year.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 9 of 28
Page 179
6.Pension Expense – Unamortized Actuarial Gains/Losses and Prior Service Costs
26. As part of Enbridge Gas’s 2024 Rates Phase 1 Decision and Order, the OEB denied
the proposed recovery of the remaining Pension and OPEB expenses recorded in
the APCDA (Union pre-2017 unamortized actuarial gains/losses), and as such the
amounts were written off leaving no balance to be disposed of7.
7 EB-2022-0200, OEB Decision and Order, December 23, 2023, pp. 101-107.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 10 of 28
Page 180
ENBRIDGE GAS - TAX VARIANCE DEFERRAL ACCOUNT (TVDA)
1. Establishment of the Enbridge Gas Inc. - Tax Variance Deferral Account was
approved by the OEB in Enbridge Gas’s 2019 Rates (EB-2018-0305) Final Rate
Order1. The purpose of this account is to record 50% of the revenue requirement
impact of any tax rate changes, versus the tax rates included in rates that affect
Enbridge Gas. In accordance with the OEB’s July 25, 2019 letter, Accounting
Direction Regarding Bill C-97 and Other Changes in Regulatory or Legislated Tax
Rules for Capital Cost Allowance, also accumulated in this account is 100% of the
revenue requirement impact of any changes in Capital Cost Allowance (CCA) that
are not reflected in base rates. This includes impacts related to Bill C-97 CCA rule
changes, which became effective November 21, 2018, as well as any future CCA
changes instituted by relevant regulatory or taxation bodies. Tax rate and CCA rule
change impacts recorded in the account will, however, exclude tax rate and rule
change impacts that are captured through other deferral account mechanisms (i.e.,
through the Incremental Capital Module Deferral Account and respective Capital
Pass-through Project Deferral Accounts).
2.The balance in the Enbridge Gas Tax Variance Deferral Account at the end of 2023
is comprised of the following:
Table 1
Details of 2023 TVDA Balances
Line No. Amount ($ millions)
1 2022 True up to T2 Filing balance2 1.816
2 2023 Non-integration related balance3 (30.299)
3 Total Balance (28.483)
1 EB-2018-0305, Final Rate Order dated October 24, 2019, Appendix I, p. 10. 2 Represents the true-up to Accelerated CCA impact between the 2022 Earnings Sharing amount submitted and the amount reflected as per the 2022 T2 Corporate Income Tax return filed after 2022 Earnings Sharing submission.
3 Represents the Acclerated CCA impact for 2023 in-service additions exclusive of ICM, CPT and Integration related.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 11 of 28
Page 181
3.As noted above, the balance requested for clearance within this proceeding is a
credit of $28.483 million, plus forecast interest of $2.715 million, for a total credit of
$31.198 million. Of the principal balance in the account, a debit of $1.816 million
relates to a true-up of the 2022 accelerated CCA impact which reflects the impact of
a variance between the 2022 qualifying additions captured in the 2022 Enbridge Gas
Tax Variance Deferral Account examined in the EB-2023-0092 proceeding, and the
final 2022 qualifying additions supporting Enbridge Gas’s 2022 tax filing. The 2023
balance of $30.299 million relates to the 2023 accelerated CCA impact on non-
integration related assets and additions. The accelerated CCA impacts of Bill C-97
were the only tax rate changes that impacted 2023. Please refer to Exhibit C, Tab 1,
Schedule 3 for details of the Tax Variance Account calculation.
4.As noted in the account description, the Tax Variance Deferral Account does not
include the accelerated CCA impacts related to capital pass-through and
incremental capital module projects, which have been reflected in the determination
of variances recorded in deferral accounts associated with those respective projects.
5.Consistent with the OEB’s EB-2022-0200 Decision and Order, dated December 21,
20234, the entire balance related to integration capital projects in the TVDA shall be
disposed of in favour of Enbridge Gas. As per the direction in the Decision and
Order, Enbridge Gas has no remaining integration related balance to bring forward
in this account.
1.Income Tax - Bill C-97 (Accelerated CCA) - Calculation
6.To calculate the annual income tax (or earnings) impact of accelerated CCA,
Enbridge Gas has maintained a continuity of the 2018 – 2023 total annual capital
additions which have qualified for accelerated CCA, and then removed the annual
additions related to capital pass-through, incremental capital module, and integration
projects. For the remaining qualifying additions, the cumulative annual CCA has
been calculated utilizing the accelerated rates and compared against the cumulative
4 EB-2022-0200, Decision and Order dated December 21, 2023, p.77.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 12 of 28
Page 182
annual CCA calculated at the non-accelerated rates. The annual income tax (or
earnings) impact of the variance between the two methodologies was then grossed-
up for taxes to determine the annual revenue requirement impact. These annual
impacts, representing 100% of the revenue requirement impact, have been recorded
each year in the Enbridge Gas Inc. – Tax Variance Deferral Account. Please see
Exhibit C, Tab 1, Schedule 3 for continuity schedules supporting the calculation of
the 2023 accelerated CCA impact.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 13 of 28
Page 183
ENBRIDGE GAS – INTEGRATED RESOURCE PLANNING OPERATING COSTS DEFERRAL ACCOUNT
1.On July 22, 2021, the OEB released its Decision and Order (EB-2020-0091) for
Enbridge Gas’ Integrated Resource Planning (IRP) Proposal. In this Decision, the
OEB approved the establishment of an IRP Operating Costs Deferral Account for all
IRP operations, maintenance, and administrations costs, and a separate IRP Capital
Costs Deferral Account for IRP project plan costs.
2.On August 12, 2021, Enbridge Gas filed its draft accounting orders for the IRP
Operating Costs Deferral Account and IRP Capital Cost Deferral Account. On
September 2, 2021, the OEB found that the draft accounting orders were consistent
with the Decision and Order and approved the accounts as filed.
3.The purpose of the IRP Operating Costs Deferral Account, as established in the
OEB’s EB-2020-0091 Decision and Order, is to record incremental IRP general
administrative costs, as well as incremental operating and maintenance costs and
ongoing evaluation costs for approved IRP Plans. Operating costs associated with
approved IRP Plans would also include all enabling payments to service providers,
made as part of the IRP Plans.
4.The balance in the 2023 IRP Operating Costs Deferral Account that is being
requested for clearance within this proceeding is a debit of $3.081 million, plus
forecast interest of $0.247 million, for a total debit of $3.328. This amount is
attributable to incremental Enbridge Gas staff salaries including expenses for IRP
related work performed in 2023, the implementation of Integrated Resource Plan
Alternatives (IRPA(s)) to defer a project in Kingston and non-labour costs such as
consulting and legal costs. The OEB in its IRP Decision approved “incremental IRP
administrative costs required to meet the increased workload related to IRP”1 … ‘be
treated as expenses and recorded in this account [operating costs deferral
account].”2
1 EB-2020-0091, OEB Decision and Order, July 22, 2021, p. 71. 2 Ibid, p. 75.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 14 of 28
Page 184
5.Table 1 provides details and a breakdown of the expenditures included in the 2023
IRP Operating Costs Deferral Account.
Table 1
Details of Expenditures – IRP Operating Costs
Line No. Item Description Millions ($)
1 Incremental FTE’s Salaries, loadings and expenses $2.680
2 East Kingston Creekford Rd Project Project costs $0.278
3 Posterity Group Model enhancement costs $0.113
4 Stakeholder Engagement Promotion and materials $0.010
5 Total Requested for Clearance $3.081
6 IRP Pilot Projects Not Requested for Clearance $0.061
7 Total in IRP Operating Cost DA $3.142
1.Incremental Full Time Equivalent’s and expenses:
6.In 2023, there were 16 Full Time Equivalent (FTE) positions and employee
expenses associated with IRP, all of which are accounted for in the 2023 IRP
Operating Costs Deferral Account. This is in addition to the 3 FTE IRP roles that are
already captured in O&M. These 16 FTE roles perform IRP work that is incremental
to what was performed by the organization prior to the IRP Decision.3
7.The incremental work that has arisen for the organization because of implementing
the OEB’s IRP Decision includes:
•Binary screening and technical evaluations of facility projects in the Asset
Management Plan and optimization of the AMP to include IRP Plans;
•Economic analysis of those projects with a technically feasible IRPA(s);
•Support the technical and economic evaluation of ETEE and demand
response IRPAs, as well as design and, once approved, support the delivery
and ongoing evaluation of IRP Plans, including Pilot Projects;
3 EB-2020-0091.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 15 of 28
Page 185
•Development and implementation of regional, geo-targeted and pilot specific
IRP stakeholder engagement activities, as well as an increased level of direct
engagement with a number of key IRP stakeholders; and
•Regulatory support for IRP Plans, and for traditional Leave-to-Construct
(LTC) proceedings.
8.To ensure that IRP is considered and supported within the Community Engagement,
Municipal Energy Solutions, Distribution Optimization Engineering (DOE), Asset
Management, Demand Side Management (DSM), Regulatory, Storage and
Transmission, and Finance departments, IRP resources have been hired directly
into their respective teams. These FTE’s work closely with and under the guidance
and oversight of the IRP team. This ensures a strong, ongoing, focus remains on the
coordination and implementation of integrated resource planning across the
organization.
9. Table 2 provides a description of the roles and responsibilities of the incremental
IRP FTEs included in the 2023 IRP Operating Costs Deferral Account. The work
completed as of the end of 2023 is outlined in the 2023 IRP Annual Report which will
be filed with the OEB by early July 2024.
Table 2 Description of FTE Additions – IRP
Line No. Role Number
of FTEs Department Responsibilities
1 Senior
Advisor /
Advisor
2 Community Engagement Manage, support and execute on the overall development and implementation of the stakeholder engagement components for IRP regional, geotargeted, and pilot specific engagements, including (1) planning and implementation of engagements, (2) gathering and incorporating stakeholder feedback from and into regional stakeholder plans, including for pilots projects, (3) Supporting the creation of IRP stakeholder specific communications materials, including website, webinars, invites, etc., and (4) assisting with the response to incoming stakeholder inquiries.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 16 of 28
Page 186
Table 2 (Continued) Description of FTE Additions – IRP (Continued)
Line No. Role Number
of FTEs Department Responsibilities
2 Senior
Advisor /
Engineer
2 Distribution Optimization Engineering (DOE)
Perform technical evaluations on projects that pass binary screening in the AMP, including: (1) model how each IRPA option, or combination of options, impacts the project needs and design to support IRP technical feasibility evaluations, (2) support the development of IRP Plans, including pilot projects, by completing the system modeling required to understand the projects’ needs and design, (3) Lead the analysis of hourly data gathered from control groups and IRPA participants (where AMI is available) to support Enbridge Gas’s ongoing development of design hour reduction assumptions for IRPAs.
3 Supervis
or
1 DOE Provide leadership and support for the DOE technical leads’ work noted above. Provide technical expertise to the broader group of internal IRP resources as well as in external engagements.
4 Advisor 2 IRP Support the development and filing of the annual IRP Report. Support the IRP Technical Working Group. Support IRP stakeholder engagement, including related Indigenous engagement activities, including the IRP web/digital plans. Support the technical evaluations of facilities projects / IRP alternatives. Develop evidence for regulatory filings/proceedings related to IRP projects. Support the implementation of IRP Plans, including two pilot projects. Project manage internal activities associated with IRP Plans and LTC applications.
5 Specialist II 1 Asset Management Liaison between Asset Class Managers and Integrated Resource Planning to complete binary screening of facility projects in the Asset Management Plan. Ensure adherence to stipulated timelines to support the consideration of IRPAs as part of the AMP process. Liaise with Asset Management Governance, Regulatory, and Public Affairs and Communications to ensure regulatory and stakeholder expectations around IRP are met during annual optimization/decision reporting activities. Support IRP Plan and traditional infrastructure proceedings to ensure compliance with the criteria set out in the IRP Decision4. Support Asset Management team in ongoing alignment of Asset Investment Strategies and Integrated Resource Planning strategies.
4 EB-2020-0091.
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EB-2024-0125
Exhibit C
Tab 1
Page 17 of 28
Page 187
Table 2 (Continued) Description of FTE Additions – IRP (Continued)
Line No. Role Number of FTEs Department Responsibilities
6 Senior Advisor 1 DSM Support the technical and economic evaluation of ETEE and demand response IRPAs, as well as design and, once approved, support the delivery and ongoing evaluation of IRP Plans, including Pilot projects.
7 Senior Advisor 2 Regulatory Provides guidance specific to interpretation of the IRP Framework5 for various departments within Enbridge Gas. Participate in project-specific discussions regarding Integrated Resource Planning considerations. For each Project where Enbridge Gas is required to apply to the OEB for LTC approval, review various aspects of integrated resource planning (including the conclusions drawn from the Binary Screening Criteria assessment, IRP alternatives assessment, etc.) throughout the OEB proceeding including during evidence development, the development of responses to interrogatories, in oral or written argument, etc. Participate in discussions regarding preparations for IRP Technical Working Group meetings and responses to requests from the IRP Technical Working Group. Review, support and provide input to the development of the IRP Annual Report and deferral account applications. Manage Applications to the OEB for IRP Pilot Projects and all future IRP Plan approvals (including management of all aspects of the regulatory proceeding). Support Conditions of Approval reporting to the OEB as applicable to IRP Pilot Projects and IRP Plan Projects.
8 Engineer 0.5 Storage & Transmission Perform technical evaluations on potential LTC projects. This includes providing modelling and analysis of how each IRPA option, or combination of options, impacts the project needs and design to support IRP technical feasibility evaluations (i.e., IRPA for Transmission Systems include: usage of Supply-side, CNG, LNG, ETE, PDO from Empress or other supply points, Contract customer Firm to IT conversions).
9 Advisor 2 Municipal Energy Solutions Execute IRP engagement activities with municipalities, inclusive of contact identification, outreach, and ongoing engagement requirements. Involvement across forums to communicate with stakeholders on IRP activities such as conferences and open houses. Geo-targeted outreach with municipalities regarding IRP projects assessed for their communities as required, inclusive of the Pilot Projects ensuring municipal support.
5 Ibid.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 18 of 28
Page 188
Table 2 (Continued) Description of FTE Additions – IRP (Continued)
Line No. Role Number of FTEs Department Responsibilities
10 Specialist / Senior Advisor
2 Finance Participate as core Enbridge Gas representatives on the IRP Technical Working Group, specific to the Discounted Cash Flow (DCF+) methodology. Prepare the IRP DCF+ Supplemental Guide and support associated regulatory review activities. Partner with internal business units in evaluating IRP projects at various stages including identification, due-diligence, assessment, approval, budgeting, and forecasting. Build and maintain comprehensive financial models for new IRP projects including integrated financial statements, standardized evaluation metrics and appropriate tax, financing, accounting, and regulatory considerations. Prepare evidence and interrogatory responses for submission to the Ontario Energy Board OEB for IRP and Rate and Facilities Applications/Hearings. Support Enbridge Gas project approval process through the preparation of standardized materials, detailed review of financial models and response to inquiries by stakeholders. Prepare reports and documentation to satisfy all regulatory reporting requirements and internal decision records. Support the implementation of two IRP alternative pilot projects and future non-pilot IRP Plans.
11 Director 0.5 IRP This role is responsible for the integration strategy and implementation of IRP.
2.East Kingston Creekford Rd Project
10. Enbridge Gas is proposing to recover $0.278 million in the IRP Operating Costs
Deferral Account related to the IRP alternative that was implemented to defer a
pipeline reinforcement project in the Kingston, Ontario area.
11. The East Kingston Creekford Rd Reinforcement project was a planned $24.3 million
capital reinforcement. Enbridge Gas determined that this project could be deferred
by implementing a supply side IRP alternative in the form of CNG beginning in
2022.6 Without the CNG injection, the Kingston system was anticipated to fall below
its minimum pressure requirements as early as the Winter of 2022/2023. An
6 For a detailed description of the pipeline project and IRP alternatives please see EB-2023-0092, Exhibit C, Tab 1, pp. 20 – 24.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 19 of 28
Page 189
agreement for CNG in 2022 ensured Enbridge Gas maintained a safe and reliable
system for customers in the Kingston project service area. The CNG agreement was
executed July 1, 2022, for the winters of 2022/2023 and 2023/2024 to ensure an in-
service date of December 1, 2022. The contracted CNG service is an enabling
payment to a competitive service provider, where Enbridge does not own the asset,
per the IRP Decision EB-2019-0091. The 2022 charges for the CNG Agreement
were approved for recovery in the IRP Operating Costs Deferral Account7 and the
$0.278 is the 2023 cost of the CNG agreement.
12. The CNG agreement provided time for Enbridge Gas to implement a Contract
turnback to reduce contract demand avoiding the facilities project. The turnback
provided, 2,200 m3/hour and was confirmed by the Contract Customer on November
11, 2022. This capacity was sufficient to defer the reinforcement; however, it was not
received in time to avoid a CNG contract back-up solution. Enbridge Gas is no
longer seeking recovery of the lost revenue associated with the contract demand
reduction for this project.8 In the event foregone revenue is a consideration when
assessing a future facility project, Enbridge Gas will file evidence on the recovery of
such amounts at that time.
13. Enbridge Gas will monitor the demands in this area to ensure the CNG solution and
contract reduction realized continue to meet the needs. CNG was procured for the
winters of 2022/2023 and 2023/2024 as noted above. In 2024, Enbridge Gas will
need to revisit the demands in the area to determine if the CNG IRPA will be
required in the winter of 2024/2025. The project will continue to be re-evaluated from
a facility and IRP perspective to understand projected demands and to reassess
depth of cover and class location issues to determine if a future facility or IRP
alternative will be required in this area.
7 EB-2023-0092, OEB Decision and Settlement Proposal and Rate Order, February 6, 2024, p.4. 8 EB-2023-0092, Settlement Proposal, Exhibit N1, Tab 1, Schedule 1, November 28, 2023, p. 7.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 20 of 28
Page 190
3. Posterity – General Model Enhancements
14. Enbridge Gas is proposing to recover $0.113 million in the IRP Operating Costs
Deferral Account related to enhancements made to Posterity’s proprietary model.
15. Enbridge Gas engaged Posterity in 2019 to develop an IRPA Model to support
estimation of peak demand reduction potential from enhanced targeted energy
efficiency (ETEE) and demand response (DR) measures. The IRPA Model uses the
DSM “mirror model” of the 2019 Achievable Potential Study (APS)9 as a basis;
where additional calibration and development of load shapes were layered onto the
“mirror model” to create the IRPA Model.
16. Enbridge Gas engaged Posterity in 2022 to further update the IRPA Model and
refine aspects of the modelling approach to improve the accuracy of future IRPA
analysis. This work continued through 2023 and will be completed in 2024.
17. The key activities involved in this model enhancement include:
a. Completing a data refresh: This included updating and recalibrating the base
year data and reference case growth forecast to the most recent available
data.
b. Recalibrating end use load shapes at a sector or rate zone level to align with
modelled design temperatures and exploring how different measures impact
base loads versus heating loads and the impact on annual versus peak hour
savings.
c.Refinement of the selection of ETEE measures and program costs to better
reflect differences in objectives between DSM and IRP.
d.Review of different scenarios (i.e., reference case, DSM business-as-usual,
technical potential, etc.) and the methodology and assumptions behind each,
such as net-to-gross (NTG), optimizing costs based on annual versus peak.
9 EB-2021-0002, Exhibit E, Tab 4, Schedule 7, Attachment 1.
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EB-2024-0125
Exhibit C
Tab 1
Page 21 of 28
Page 191
4.Stakeholder Engagement
18. Enbridge Gas is proposing to recover $0.010 million in the IRP Operating Costs
Deferral Account related to the stakeholder activities completed in 2023. General
stakeholder efforts included the promotion of regional webinars in the spring and fall.
Enbridge Gas also developed print materials for engagement at Conferences
throughout 2023.
5. IRP Pilot Projects
19. Additional operating costs of approximately $0.061 million and capital costs of
$0.015 million have been incurred in 2023 related to the IRP Pilot Project application
(EB-2022-0335). Recovery of these amounts will be requested after the OEB
Decision on the Pilot Project application.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 22 of 28
Page 192
ENBRIDGE GAS – GETTING ONTARIO CONNECTED ACT VARIANCE ACCOUNT
1. Establishment of the Getting Ontario Connected Act (GOCA) variance account was
approved by the OEB in EB-2023-01431. The purpose of the GOCA variance
account is to track incremental pipeline locate costs resulting from the enactment of
Bill 93 on April 14, 2022. Bill 93 included amendments to the Ontario Underground
Notification System Act, 20122 and the Building Broadband Faster Act, 20213. The
GOCA variance account is intended to continue for each year of the current IR term
(2024 to 2028).
2. Based on 2021 external contractor costs Enbridge Gas was expecting to pay
approx. $34 per locate in 2023, however the actual cost paid for a locate rose to $72
a 111% increase over expectation. The increase in cost was a direct result of Bill 93
which imposed a five-business-day deadline for completing standard locate requests
and introduced administrative penalties for failing to comply. Bill 93 has resulted in
incremental locating costs to meet this compliance mandate that are not covered by
current rates. This evidence outlines the drivers behind Bill 93 cost increases as well
as the incremental cost calculations.
3. The balance of the 2023 GOCA account that is being requested for clearance is
$31.903 million plus interest of $1.736 million for a total debit balance of $33.639
million. The background and methodology employed on arriving at this amount are
outlined in detail below.
4. In its EB-2023-0143 decision, the OEB issued an accounting order for gas utilities to
establish the GOCA variance account to record the variance between locate costs
resulting from Bill-93 and the approved cost included in base rates.
1 EB-2023-0143, Decision and Order, October 31, 2023.
2 Bill 8, Ontario Underground Infrastructure Notification System Act, 2012, June 19, 2012.
https://www.ola.org/en/legislative-business/bills/parliament-40/session-1/bill-8
3 Bill 257, Supporting Broadband and Infrastructure Expansion Act, April 12, 2021
https://www.ola.org/en/legislative-business/bills/parliament-42/session-1/bill-257
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 23 of 28
Page 193
5. According to the OEB,
“This account includes costs incurred to enable the locate activities. Utilities
are expected to track costs at a sufficiently detailed level to assist in a review
of the costs incurred, materiality, and causation related to Bill 93 at the time
of disposition. Specifically, utilities are to demonstrate that recorded amounts
in their accounts are both incremental to the base rates and are a direct
result of Bill 93.”4
The OEB also indicated that only amounts incurred on or after April 1, 2023, were to
be recorded in this account. Following OEB guidance, Enbridge Gas has employed
a methodology to capture incremental locating costs that are directly attributable to
Bill 93 on or after April 1, 2023.
6.Bill 93 has directly resulted in incremental costs outside of base rates in two areas:
the cost of the locate itself, and in vital main standby (VMS) costs – a locate-related
service requiring an experienced locator skillset and therefore provided by the same
locate service providers (LSP).
1. Drivers Behind Bill 93 Cost Increases
7. Locate costs have increased due to the new legislated locate delivery timelines
resulting from Bill 93. Enbridge Gas’s average locate delivery times were 13 days
and 15 days in 2021 and 2022 respectively. Bill 93 legislates a 5 day locate delivery
mandate and introduces administrative penalties for non-compliance. This change in
timeline is analogous to checking customers out of a grocery store. If the volume of
customers stays the same and you want to speed up the check out times, more
registers are needed. To meet the 5 day locate delivery timeline, LSPs were
required to onboard a significant amount of new locators, as well as increase locator
wages to attract and retain qualified talent under tight labour market conditions. Bill
93 put legislation in place recognizing locators as a highly skilled industry
requirement. LSPs renewed unionized labour contracts in 2022, and based on the
new operating environment and industry recognition of locating as a highly skilled
trade, unionized wages increased significantly. This increased wage cost resulted in
4 EB-2023-0143, OEB Decision and Order, October 31, 2023, Schedule B, p. 17.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 24 of 28
Page 194
higher contract service costs for Enbridge Gas and the other ~15 utilities in the
Locate Alliance Consortium (LAC).
8. As a result of LSPs onboarding additional locators and locator wage increases,
locating costs are up significantly for Enbridge Gas. Quite simply, Bill 93 required
Enbridge Gas to shave an average of 10 days off its locate delivery time and the
only way to achieve this was to have more locators. This coincided with LSP union
negotiations where labour rates increased significantly to match the new industry
skillset requirements and to attract/retain more specialized talent. This increase in
locators and rates have caused the Enbridge Gas cost per locate to double. As
mentioned above, the 2021 average external contractor cost per locate was $34 and
the 2023 average external contractor cost per locate was $72, a 111% increase.
Enbridge Gas has included incremental external locating costs related to Bill 93 in
the GOCA variance account.
9. VMS is a program, requiring a LSP skillset, designed to ensure public safety when
excavations take place within the vicinity of vital natural gas infrastructure in the
public right of way. The VMS program prevents damages, energy outages, and
protects the public and excavators by ensuring locates are recognized and proper
procedures and safety controls are followed throughout the excavation process
within the vicinity of the located vital assets.
10. As previously noted, Bill 93 has resulted in increased labour rates for LSPs which
has created parallel incremental costs in the Enbridge Gas VMS program since this
service is performed by the same contractors. The 2021 average external contractor
cost per hour was $82 and the 2023 average external contractor cost per hour was
$146, a 78% increase. Enbridge Gas has therefore included incremental external
locator costs for the VMS program in the GOCA variance account.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 25 of 28
Page 195
2. Incremental Bill 93 cost calculations
11. Enbridge Gas has calculated incremental costs directly related to Bill 93 using 2021
actual locate costs adjusted for inflation and 2023 locate volumes as a baseline.
2021 actual locate costs were used as they provide an accurate calculation of pre
Bill 93 locating costs.
12. The EGI locates budget included in base rates with OEB approved Price Cap Index
(PCI)5 was $26.4 million for 2021, in comparison to actual 2021 costs of $34.5
million. Enbridge Gas will not seek to recover the increased spend from base rates
as it was deemed unrelated to Bill 93.
13. Actual 2021 locating costs were $34.5 million. To incorporate inflationary impacts,
the PCI values for 2022 and 2023 were applied resulting in an inflation adjusted cost
of $36.2 million6. After adjusting for 2023 actual locate volumes, the calculated
annual base locate cost for 2023 is $33.1 million. Please refer to Table 1 outlining
the calculations.
Table 1
Base Locates Costs
Line
No. Particulars Amount
1 A 2021 Actual Locate Costs $ 34,464,465
2 B PCI Inflation (2022, 2023) $ 1,740,593
3 C = A*B Inflation Adjusted Locate Costs $ 36,205,058
4 D 2021 Locate Volumes 1,068,953
5 E = C/D Inflation Adjusted Costs per Locate $33.87
6 F 2023 Actual Locate Volumes 975,919
7 G = E*F Base Locate Costs (full year) $33,054,030
14. The same logic was used to calculate VMS costs which are contractually billed to
Enbridge Gas hourly. Actual 2021 VMS costs were $3.3 million resulting in an
inflation adjusted cost of $3.5 million7. After adjusting for 2023 actual VMS hours, the
5 PCI percentages were 1.4% for 2022 and 3.6% in 2023.
6 $34.5 million x 1.014 x 1.036 = $36.2 million.
7 $3.3 million x 1.014 x 1.036 = $3.5 million.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 26 of 28
Page 196
calculated annual base VMS cost for 2023 is $4.9 million. Please refer to Table 2
outlining the calculations.
Table 2
Base VMS Costs
Line
No. Particulars Amount
1 A 2021 Actual VMS Costs $ 3,300,909
2 B PCI Inflation (2022, 2023) $ 166,709
3 C = A*B Inflation Adjusted VMS Costs $ 3,467,618
4 D 2021 Volumes (VMS Hours) 40,086
5 E = C/D Inflation Adjusted VMS Costs per Hour $ 86.50
6 F 2023 Actual Volumes (VMS Hours) 57,046
7 G = E*F Base VMS Costs (full year) $ 4,934,734
15. The calculated annual base locate and VMS costs for 2023 were $33.1 million and
$4.9 million respectively. To determine costs incurred on or after April 1, 2023, these
costs were separated using a weighted cost approach to determine monthly costs
for these expenditures. This weighted cost approach results in base locate & VMS
costs for April 1, 2023 - December 31, 2023 of $29.2 million for locates and $4.4
million for VMS. Actual locate and VMS costs for this same period in 2023 resulted
in $58.1 million for locates and $7.4 million for VMS. Please refer to Table 3 and
Table 4 outlining the calculations.
Table 3
Locates Monthly Profile
($millions)
Amount
Line
No. Particulars Jan to Mar Apr to Dec
1 A 2023 Actual Locate Costs $7.7 M $58.1 M
2 B % of Year Total 11.7% 88.3%
3 C= B*$33.1M Locates Base Costs $3.9 M $29.2 M
4
A-C
2023 Actual less Base
Costs $3.8 M $28.9 M
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 27 of 28
Page 197
Table 4
VMS Monthly Profile
($millions)
Amount
Line
No. Particulars Jan to Mar Apr to Dec
1 A 2023 Actual VMS Costs $0.9 M $7.4 M
2 B % of Year Total 10.9% 89.1%
3 C= B*$4.9M VMS Base Costs $0.5 M $4.4 M
4 A-C 2023 Actual less Base Costs $0.4 M $3.0 M
16. 2023 total actual costs less the weighted base costs are $28.9 million8 for locates
and $3 million9 for VMS, as per Table 3 and Table 4 ($31.9 million total). The
balance of the 2023 GOCA account that is being requested for clearance is $31.903
million plus interest of $1.736 million for a total debit balance of $33.639 million.
17. The proposed split of the GOCA variance account balance ($33.639 million)
between the EGD rate zone, Union North rate zone and Union South rate zone is
based on the number of locates completed within each rate zone during 2023.
Please refer to table 5 for the proposed breakdown.
Table 5
2023 Completed Locate Weighting
($millions)
Line
No. Description Amount
1 EGD Total 62.0% $20.9 M
2 Union North Total 7.3% $2.5 M
3 Union South Total 30.7% $10.3 M
4 Total $33.639 M
18. The proposed cost allocation methodology to dispose of the GOCA variance account
to rate classes in each rate zone is described at Exhibit F, Tab 1, page 4.
8 $58.1 million – $29.2 million = $28.9 million.
9 $7.4 million - $4.4 million = $3.0 million.
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Page 28 of 28
Page 198
Col. 1 Col. 2 Col. 3 Col.4
Line Account Reference to
No. Account Description Acronym Principal Interest Total Evidence
($000's) ($000's) ($000's)
EGD Rate Zone Commodity Related Accounts
1. Storage and Transportation D/A 2023 S&TDA 18,705.8 1,572.8 20,278.6 D-1, Page 1
2.Transactional Services D/A 2023 TSDA (41,738.1) (2,291.5) (44,029.6) D-1, Page 3
3.Unaccounted for Gas V/A 2023 UAFVA (6,922.7) (266.5) (7,189.2) D-1, Page 5
4. Total Commodity Related Accounts (29,955.0)(985.2) (30,940.2)
EGD Rate Zone Non Commodity Related Accounts
5. Average Use True-Up V/A 2023 AUTUVA 14,307.1 785.5 15,092.6 D-1, Page 69
6. Gas Distribution Access Rule Impact D/A 2023 GDARIDA - - - D-1, Page 79
7. Deferred Rebate Account 2023 DRA 2,132.7 187.1 2,319.8 D-1, Page 71
8. Transition Impact of Accounting Changes D/A 2023 TIACDA - - - D-1, Page 79
9. Electric Program Earnings Sharing D/A 2023 EPESDA - - - D-1, Page 79
10. Open Bill Revenue V/A 2023 OBRVA - - - D-1, Page 79
11. Ex-Franchise Third Party Billing Services D/A 2023 EFTPBSDA - - - D-1, Page 79
12. OEB Cost Assessment V/A 2023 OEBCAVA 3,732.8 302.1 4,034.9 D-1, Page 72
13. Dawn Access Costs D/A 2023 DACDA - - - D-1, Page 79
14. Incremental Capital Module D/A - EGD 2020-2023 ICMDA (4,909.0) (232.4) (5,141.4) D-1, Page 75
15. RNG Injection Service V/A 2022-2023 RNGISVA (331.5)(28.7)(360.2) D-1, Page 77
16. Pension and OPEB Forecast Accrual vs. Actual Cash Payment Differential V/A 2023 P&OPEBFAVACPDVA - - - D-1, Page 79
17.Total EGD Rate Zone (for clearance) (15,022.9)28.4 (14,994.5)
Union Rate Zones Gas Supply Accounts OEB Account Number
18. Upstream Transportation Optimization 179-131 2023 8,087.2 444.0 8,531.2 E-1, Page 6
19. Spot Gas Variance Account 179-107 2023 - - - E-1, Page 55
20. Unabsorbed Demand Costs Variance Account 179-108 2023 41.5 37.8 79.3 E-1, Page 1
21. Base Service North T-Service TransCanada Capacity 179-153 2023 79.0 5.6 84.6 E-1, Page 45
22. Total Gas Supply Accounts 8,207.7 487.4 8,695.1
Union Rate Zones Storage Accounts
23. Short-Term Storage and Other Balancing Services 179-70 2023 1,637.5 89.9 1,727.4 E-1, Page 8
Union Rate Zones Other Accounts
24. Normalized Average Consumption 179-133 2023 (3,650.8) (201.3) (3,852.1) E-1, Page 12
25. Deferral Clearing Variance Account 179-132 2023 3,372.3 184.5 3,556.8 E-1, Page 19
26. OEB Cost Assessment Variance Account 179-151 2023 1,630.3 131.1 1,761.4 E-1, Page 42
27. Unbundled Services Unauthorized Storage Overrun 179-103 2023 - - - E-1, Page 55
28. Gas Distribution Access Rule Costs 179-112 2023 - - - E-1, Page 55
29. Conservation Demand Management 179-123 2023 - - - E-1, Page 55
30. Parkway West Project Costs 179-136 2023 (696.4)(48.7)(745.1) E-1, Page 20
31. Brantford-Kirkwall/Parkway D Project Costs 179-137 2022 (3.1)(0.3)(3.4) E-1, Page 23
32. Lobo C Compressor/Hamilton-Milton Pipeline Project Costs 179-142 2023 267.8 10.3 278.1 E-1, Page 33
33. Lobo D/Bright C/Dawn H Compressor Project Costs 179-144 2023 66.0 (39.5) 26.5 E-1, Page 37
34. Burlington-Oakville Project Costs 179-149 2023 (43.3)(3.1)(46.4) E-1, Page 40
35. Panhandle Reinforcement Project Costs 179-156 2023 (1,884.1) (145.9) (2,030.0) E-1, Page 46
36. Sudbury Replacement Project 179-162 2023 - - - E-1, Page 55
37. Parkway Obligation Rate Variance 179-138 2023 - - - E-1, Page 55
38. Unauthorized Overrun Non-Compliance Account 179-143 2023 (45.5)(4.3)(49.8) E-1, Page 36
39. Incremental Capital Module D/A - UGL 179-159 2019-2023 (383.7) (504.0)(887.7) E-1, Page 52
40. Pension and OPEB Forecast Accrual vs. Actual Cash Payment Differential V/A 179-157 2023 - (6,207.7)(6,207.7) E-1, Page 49
41. Unaccounted for Gas Volume Variance Account 179-135 2023 - - - E-1, Page 25
42. Unaccounted for Gas Price Variance Account 179-141 2023 (629.1) (132.3)(761.4) E-1, Page 30
43. Total Other Accounts (1,999.6) (6,961.2)(8,960.8)
44.Total Union Rate Zones (for clearance)7,845.6 (6,383.9)1,461.7
EGI Accounts
45. Earnings Sharing D/A 179-382 2023 - - - C-1, Page 1
46.Tax Variance - Accelerated CCA - EGI 179-383 2023 (28,483.3) (2,715.0) (31,198.3) C-1, Page 11
47. IRP Operating Costs Deferral Account 179-385 2023 3,081.2 247.3 3,328.5 C-1, Page 14
48. IRP Capital Costs Deferral Account 179-386 2023 - - - C-1, Page 22
49. Green Button Initiative D/A 179-387 2023 - - - C-1, Page 1
50. Cloud Computing Implementation Costs D/A 179-332 2023 - - - C-1, Page 1
51. Getting Ontario Connected V/A 179-324 2023 31,902.6 1,736.2 33,638.8 C-1, Page 23
52. Expansion of Natural Gas Distribution Systems V/A 179-380 2023 - - - C-1, Page 1
53.Accounting Policy Changes D/A - Other - EGI 179-381 2019-2023 5,511.3 36.2 5,547.5 C-1, Page 2
54. Impacts Arising from the COVID-19 Emergency D/A - EGI 179-384 2020-2021 - - - C-1, Page 1
55. Total EGI Accounts (for clearance)12,011.8 (695.3) 11,316.5
56. Total Deferral and Variance Accounts (for clearance)4,834.5 (7,050.9) (2,216.4)
Forecast for clearance at
January 1, 2025
Actual & Forecast Balances
Deferral & Variance AccountEnbridge Gas
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Schedule 1 Page 1 of 1
Page 199
Line
No.
Interest During
Construction
Depreciation
Expense
Overhead
Capitalization
Amortized Gas
Supply Storage
and
Transportation
Costs
Subtotal Pension Expense Total
1 Balance at December 31,
2022 (13.059)0.601 (18.459)1.110 62.155 32.348 160.289 192.638
2 Impact to 2023 revenue
requirement:
3 Expense (8.043)0.268 (5.427) (22.188)(35.390) (160.289) (195.679)
4 Cost of capital 1.067 0.273 1.421 0.567 3.328 - 3.328
5 Income tax (0.284)(1.893)(1.725)(3.828) (7.730)- (7.730)
6 Total (7.260)(1.352)(5.731) (25.450) - (39.793) (160.289) (200.082)
7 Balance at December 31,
2023 (20.319)(0.751) (24.190) (24.339)62.155 (7.445)(0.000) (7.445)
8 Balances previously
approved for disposition (11.666)1.533 (31.229) (36.494)64.900 (12.956)- (12.956)
9 Balances proposed for
Disposition (8.653)(2.284)7.039 12.155 (2.745)5.511 (0.000) 5.511
Table 1
Revenue Requirement
($millions)
Filed: 2024-05-31
EB-2024-0125
Exhibit C
Tab 1
Schedule 2 Page 1 of 3
Page 200
LineNo. ($millions)Principal Interest TotalPrincipal Interest TotalPrincipal Interest TotalEGD Rate Zone1Capitalization vs Expense7.899 0.193 8.092 9.058 0.340 9.398 1.159 0.147 1.306 2Interest During Construction2.360 0.058 2.418 0.790 0.030 0.820 (1.570) (0.028) (1.598) 3Depreciation Expense- - - - - - - - - 4Overhead Capitalization22.627 0.554 23.181 17.114 0.643 17.757 (5.513) 0.089 (5.424) 5Amortized Gas Supply Storage & Transportation Costs64.900 1.588 66.488 62.155 2.335 64.490 (2.745) 0.748 (1.997) 6Total EGD Rate Zone APCDA97.786 2.392 100.178 89.117 3.348 92.465 (8.669) 0.956 (7.713) UGL Rate Zone7Capitalization vs Expense(19.565) (0.478) (20.043) (29.378) (1.104) (30.482) (9.813) (0.625) (10.438) 8Interest During Construction(0.827) (0.020) (0.847) (1.542) (0.058) (1.6) (0.715) (0.038) (0.753) 9Depreciation Expense(31.229) (0.764) (31.993) (24.190) (0.909) (25.1) 7.039 (0.145) 6.894 10Overhead Capitalization(59.121) (1.446) (60.567) (41.452) (1.6) (43.0) 17.669 (0.112) 17.557 11Amortized Gas Supply Storage & Transportation Costs- - - - - - - - - 12Total UGL Rate Zone APCDA(110.742) (2.708) (113.450) (96.562) (3.628) (100.190) 14.180 (0.920) 13.260 13Total APCDA(12.956) (0.316) (13.272) (7.445) (0.280) (7.725) 5.511 0.036 5.547 Notes:(1)(2) Reflects 2019 through 2023 actuals.(3) Represent variances between amounts approved for disposition in the Interim Rate Order and the final cumulative balances based on actuals.Table 2Summary of Accounting Policy Changes Deferral Account (No. 179-381)Amounts Requested for Clearance In 2023 ESM ProceedingActual & ForecastBalances Approved for DispositionEB-2022-0200 Rate Order, Working Papers, Schedule 27, pages 1 & 2; approved in Interim Rate Order dated April 11, 2024.(EB-2022-0200)1Final Cumulative Balances2 Amounts Proposed for Disposition(2023 ESM and Deferral Disposition)3Filed: 2024-05-31 EB-2024-0125 Exhibit C Tab 1 Schedule 2 Page 2 of 3Page 201
Col. 1Col. 2 Col. 3Col. 4 Col. 5 Col. 6 Col. 7Col. 8 Col. 9 Col. 10 Col. 11 Col. 12Col. 13LineNo. ($000's)EGD -Change from Capital to O&MUGL -Change from O&M to CapitalCapitalization Policy Alignment - SubtotalEGD -Change from IDC rate at WACD to Board PrescribedUGL -Elimination of IDC ThresholdIDC Policy Alignment - SubtotalDepreciation Expense Policy AlignmentEGD - Change in Overhead CapitalizationUGL - Change in Overhead CapitalizationOverhead Capitalization Alignment - SubtotalAmortized Gas Supply Storage and Transportation Costs APCDATotalActuarial Gains/Losses on UGL PensionCost of capital1Rate base (8,774.4) 22,068.1 13,293.7 (1,527.5) 5,034.6 3,507.1 19,465.2 (3,930.4) 11,100.9 7,170.5 - 43,436.50.0 2 Required rate of return*6.20%7.30%6.20%7.30%7.30%6.20%7.30%7.30%7.30%3 Cost of capital* (544.0) 1,611.0 1,067.0 (94.7) 367.5 272.8 1,421.0 (243.7)810.4 566.7 - 3,327.5- Cost of service4Gas costs- - - - - - - - - - - - - 5Operation and Maintenance 2,116.2 (10,372.2) (8,256.0)- - - - 13,519.4 (36,031.3) (22,511.9)- (30,767.9) (4,268.0)6 Depreciation and amortization (216.3) 429.3 213.0 (43.1) 311.0 267.9 (5,427.2) (110.5)434.4 323.9 -(4,622.4)- 7Municipal and other taxes- - - - - - - - - - - - - 8 Cost of service 1,899.9 (9,942.9) (8,043.0) (43.1) 311.0 267.9 (5,427.2) 13,408.9 (35,596.9) (22,188.0)- (35,390.3) (4,268.0)Income taxes on earnings9Excluding tax shield (415.9) 2,221.9 1,806.0 (742.5) (750.5) (1,493.0)- (2,388.4) 5,391.7 3,003.3 - 3,316.3 1,131.0 10 Tax shield provided by interest expense67.9 (233.9) (166.0)11.8 (53.4) (41.6) (206.3)30.4 (117.7)(87.3)-(501.2)- 11 Income taxes on earnings (348.0) 1,988.0 1,640.0 (730.7) (803.9) (1,534.6) (206.3) (2,358.0) 5,274.0 2,916.0 - 2,815.1 1,131.0 Taxes on (def) / suff.12Gross (def.) / suff. (1,371.7) 8,632.1 7,260.4 1,181.6 170.6 1,352.2 5,731.0 (14,703.9) 40,153.6 25,449.7 - 39,793.3 4,268.0 13 Net (def.) / suff. (1,008.2) 6,344.6 5,336.4 868.5 125.4 993.9 4,212.3 (10,807.4) 29,512.9 18,705.5 -29,248.1 3,137.0 14 Taxes on (def.) / suff. 363.5 (2,287.5) (1,924.0) (313.1) (45.2) (358.3) (1,518.7) 3,896.5 (10,640.7) (6,744.2)- (10,545.2) (1,131.0)15 Revenue requirement 1,371.7 (8,632.1) (7,260.4) (1,181.6) (170.6) (1,352.2) (5,731.0) 14,703.9 (40,153.6) (25,449.7)- (39,793.3) (4,268.0)16 Gross revenue (def.) / suff. (1,371.7) 8,632.1 7,260.4 1,181.6 170.6 1,352.2 5,731.0 (14,703.9) 40,153.6 25,449.7 -39,793.3 4,268.0 *Union rate zones 2013 Board-approved rate of return is 7.3% and EGD rate zone 2018 Board-approved rate of return is 6.2%.Table 3Summary of Accounting Policy Changes Deferral Account (No. 179-381)Utility Revenue RequirementFiled: 2024-05-31 EB-2024-0125 Exhibit C Tab 1 Schedule 2 Page 3 of 3Page 202
Additions Net of2022 Year-EndOpening Opening Total Additions ICM, Capital ICM, Capital Accel. CCA Regular CCAClosingClosingLineUCCUCC Qualifying for Pass-Through and Pass-Through and Depreciable Depreciable Rate Accelerated RegularUCCUCCNo. Particulars ($000s)Accel. CCA Regular CCA Accel. CCA Integration Additions Integration UCC Balance UCC Balance (%)CCACCA Accel. CCARegular CCA(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)Class1. 1 Buildings, structures and improvements, services, meters, mains----- --4%----2. 1 Non-residential building acquired after March 19, 200738,598.5 41,143.4 23,294.4 (0.9)23,295.3 73,541.4 52,791.1 6%4,395.2 3,161.7 57,498.6 61,277.0 3. 2 Mains acquired before 1988----- --6%----4. 3 Buildings acquired before 1988----- --5%----5. 6 Other buildings----- --10%----6. 7 Compression equipment acquired after February 22, 20059,220.7 11,005.4 18,981.3 -18,981.337,692.7 20,496.0 15%5,653.9 3,074.4 22,548.1 26,912.3 7. 8 Compression assets, office furniture, equipment46,664.8 59,997.6 79,647.5 -79,647.5166,136.2 99,821.4 20%33,214.5 19,960.0 93,097.9 119,685.2 8. 10 Transportation, computer equipment14,261.9 22,041.2 20,296.7 -20,296.744,707.0 32,189.5 30%13,380.7 9,646.4 21,177.9 32,691.5 9.12 Computer software, small tools-4,027.745,365.2 32,350.813,014.313,014.3 10,534.8 100% 12,456.0 10,255.7 558.46,786.3 10. 13 Leasehold improvements----- -- N/A----11. 14.1 Intangibles5,879.8 6,197.6 890.96.6884.37,206.2 6,639.7 5%360.3332.06,403.7 6,749.9 12. 14.1 Intangibles (pre 2017)----- --7%----13. 17 Roads, sidewalk, parking lot or storage areas----- --8%----14. 38 Heavy work equipment8,835.1 13,654.3 6,480.3 -6,480.318,555.6 16,894.5 30%5,555.4 5,064.6 9,760.0 15,070.0 15. 41 Storage assets48,703.6 68,185.0 42,923.7 -42,923.7113,089.2 89,646.9 25%28,272.3 22,411.7 63,355.0 88,697.0 16. 45 Computers - Hardware acquired after March 22, 2004-------45%----17. 49 Transmission pipeline additions acquired after February 23, 2005 152,266.0 166,108.3 65,636.2 -65,636.2250,720.3 198,926.4 8%20,057.6 15,914.1 197,844.6 215,830.4 18. 50 Computers hardware acquired after March 18, 20074,292.4 17,782.6 13,744.0 1,936.411,807.622,003.7 23,686.4 55%12,048.1 13,009.5 4,051.8 16,580.6 19. 51 Distribution pipelines acquired after March 18, 20071,594,705.5 1,699,850.9 870,196.3 95,445.4774,751.02,756,831.9 2,087,226.4 6% 165,409.9 125,233.6 2,204,046.5 2,349,368.3 20. Total$ 1,923,428.3 2,109,994.1 1,187,456.5 129,738.31,057,718.2 3,503,498.4 2,638,853.2 $ 300,803.9 $ 228,063.7 2,680,342.6 2,939,648.672,740.2Additions Net of2023 Year-EndOpening Opening Total Additions ICM, Capital ICM, Capital Accel. CCA Regular CCAClosingClosingLineUCCUCC Qualifying for Pass-Through and Pass-Through and Depreciable Depreciable Rate Accelerated RegularUCCUCCNo. Particulars ($000s)Accel. CCA Regular CCA Accel. CCA Integration Additions Integration UCC Balance UCC Balance (%)CCACCA Accel. CCARegular CCA(a)(b)(c)(d)(e)(f)(g)(h)(i)(j)(k)(l)Class1. 1 Buildings, structures and improvements, services, meters, mains----- --4%----2. 1 Non-residential building acquired after March 19, 200757,498.6 61,277.0 3,236.8 2.53,234.362,350.0 62,894.2 6%3,741.0 3,773.7 56,991.9 60,737.7 3. 2 Mains acquired before 1988----- --6%----4. 3 Buildings acquired before 1988----- --5%----5. 6 Other buildings----- --10%----6. 7 Compression equipment acquired after February 22, 200522,548.1 26,912.3 4,446.1 -4,446.129,217.3 29,135.3 15%4,382.6 4,370.3 22,611.6 26,988.1 7. 8 Compression assets, office furniture, equipment93,097.9 119,685.2 125,909.3 -125,909.3281,961.9 182,639.8 20%56,392.4 36,528.0 162,614.8 209,066.5 8. 10 Transportation, computer equipment21,177.9 32,691.5 3,253.9 -3,253.926,058.9 34,318.5 30%7,817.7 10,295.5 16,614.2 25,649.9 9.12 Computer software, small tools558.46,786.3 33,766.4 15,561.018,205.418,763.8 15,889.0 100% 18,763.8 15,889.0 -9,102.710. 13 Leasehold improvements------- N/A----11. 14.1 Intangibles6,403.7 6,749.9 564.0-564.07,249.8 7,031.9 5%362.5351.66,605.3 6,962.3 12. 14.1 Intangibles (pre 2017)----- --7%----13. 17 Roads, sidewalk, parking lot or storage areas----- --8%----14. 38 Heavy work equipment9,760.0 15,070.0 2,462.7 -2,462.713,454.1 16,301.4 30%4,036.2 4,890.4 8,186.5 12,642.3 15. 41 Storage assets63,355.0 88,697.0 98,405.5 -98,405.5210,963.3 137,899.8 25%52,740.8 34,474.9 109,019.7 152,627.6 16. 45 Computers - Hardware acquired after March 22, 2004-------45%----17. 49 Transmission pipeline additions acquired after February 23, 2005 197,844.6 215,830.4 25,124.4 -25,124.4235,531.1 228,392.6 8%18,842.5 18,271.4 204,126.4 222,683.4 18. 50 Computers hardware acquired after March 18, 20074,051.8 16,580.6 17,057.2 1,669.315,387.927,133.7 24,274.6 55%14,923.5 13,351.0 4,516.2 18,617.5 19. 51 Distribution pipelines acquired after March 18, 20072,204,046.5 2,349,368.3 908,359.9 25,855.2882,504.73,527,803.6 2,790,620.6 6% 211,668.2 167,437.2 2,874,883.0 3,064,435.8 20. Total$ 2,680,342.6 2,939,648.6 1,222,586.3 43,087.91,179,498.3 4,440,487.4 3,529,397.7 $ 393,671.1 $ 309,633.1 3,466,169.8 3,809,513.8201820192020202120222023CCA Variance (i) - (j) 13,580.7 70,503.0 47,308.8 55,163.572,740.2 84,038.0 Tax Rate26.5%26.5%26.5%26.5%26.5%26.5%Earnings Impact of Accelerated CCA 3,598.9 18,683.3 12,536.8 14,618.319,276.1 22,270.1 Earnings Impact Grossed-up for Taxes Recorded in the TVDA 4,896.4 25,419.5 17,056.9 19,888.926,226.0 30,299.4 Balances as filed in EB-2023-0092 4,896.4 25,133.9 16,588.8 18,694.428,042.2 N/Avariance-285.6468.21,194.5(1,816.2) -Include adjustment to 2019 balance in 2020 TVDA-(285.6)285.6-- -Include adjustment to 2020 balance in 2021 TVDA--(468.2) 468.2- -Include adjustment to 2021 balance in 2022 TVDA---(1,194.5)1,194.5-Include adjustment to 2022 balance in 2023 TVDA----1,816.2(1,816.2) Revised Balances 4,896.4 25,133.9 16,874.3 19,162.629,236.7 28,483.3 1 - Balance for 2019 was updated based on the change from EB-2020-0134 and Tax Filing on June 30, 2020.2 - Balance for 2020 was updated based on the change from EB-2021-0149 and Tax Filing on June 30, 2021.3 - Balance for 2021 was updated based on the change from EB-2022-0110 and Tax Filing on June 30, 2022.4 - Balance for 2022 was updated based on the change from EB-2023-0092 and Tax Filing on June 30, 2023.Enbridge GasCalculation of the Bill C-97 Accelerated CCA Impact to be Recorded in the Tax Variance Deferral AccountFiled: 2024-05-31 EB-2024-0125 Exhibit C Tab 1 Schedule 3 Page 1 of 1Page 203
2023 STORAGE & TRANSPORTATION DEFERRAL ACCOUNT
EGD RATE ZONES
1. The purpose of the 2023 Storage & Transportation Deferral Account (S&TDA) is to
record the difference between the forecast cost of Storage and Transportation
included in the Company’s approved rates and the actual cost of Storage and
Transportation incurred by the Company. Storage and Transportation cost includes
cost of service and market-based pricing.
2. The S&TDA also records the variance between the forecast Storage and
Transportation demand levels and the actual Storage and Transportation demand
levels. In addition, the S&TDA is used to record amounts received by the Company
related to deferral account dispositions of other utilities deferral accounts.
3. The balance in the 2023 S&TDA that the Company is proposing to collect from
customers is $18.7 million plus interest. A detailed breakdown of the S&TDA is
provided in Exhibit D, Tab 1, Schedule 1.
4. The primary driver for the balance in the 2023 S&TDA is higher than forecasted
transportation prices, higher than forecasted market-based storage costs in 2023
and a $5.9 million collection from the Union rate zone as part of Enbridge Gas’s
2021 Deferral and Variance disposition as approved by the OEB in EB-2022-0110.
Transportation prices are determined by the OEB-approved M12 Rate Schedule.
5. The market-based storage costs in 2023 were $23.8 million, which is $3.7 million
higher than the OEB approved market-based storage costs of $20.1 million. The
increase in 2023 market-based storage costs is primarily driven by the higher
average storage cost in 2023 of $0.91/GJ compared to the average storage cost in
the OEB approved market-based storage costs of $0.78/GJ.
Filed: 2024-05-31
EB-2024-0125
Exhibit D
Tab 1
Page 1 of 79
Page 204
6. As outlined in the Annual Update to the 5 Year Gas Supply Plan, Enbridge Gas
purchases market-based storage services on behalf of customers in the EGD rate
zone through a competitive blind storage RFP process. On September 21, 2022,
Enbridge Gas initiated an RFP for market-based storage capacity with deliveries to
Dawn. The RFP was conducted by Ernst & Young LLP. The RFP requested offers of
storage services with terms of up to 5 years commencing April 1, 2023 with firm
injections from May to September and firm withdrawals from December to March.
The RFP letter is provided as Exhibit D, Tab 1, Schedule 5.
7. Enbridge Gas required this annual replacement of third-party storage in order to
reliably and cost effectively meet demand on peak winter days as well as retain late
season deliverability. The RFP responses were received by Enbridge Gas on
October 11, 2022. The RFP manager made the recommendation and Enbridge Gas
transacted based on the recommendation. Bids received and those that were
selected are outlined in Confidential Exhibit D, Tab 1, Schedule 6.
Filed: 2024-05-31
EB-2024-0125
Exhibit D
Tab 1
Page 2 of 79
Page 205
2023 TRANSACTIONAL SERVICES DEFERRAL ACCOUNT (TSDA)
EGD RATE ZONE
1. The concept of Transactional Services operates under the premise that if
circumstances arise where the assets acquired by Enbridge Gas to meet customer
demand are not fully required then those assets can be made available to generate
third party revenue. Transactional Services are the optimization of these assets.
2. Transactional Services optimization can be grouped into two different categories –
storage optimization and transportation optimization. Storage optimization
transactions typically rely on the storage of or the loan of gas between two points in
time at the same location (i.e. Dawn). Transportation optimization transactions
typically rely on the exchange of gas on the day between two locations.
3. Any revenues received from Transactional Services are shared 90:10 between the
ratepayer and the Company. The EGD rate zone rates include an upfront benefit of
$12.0 million in Transactional Services revenue that has been applied to reduce the
overall costs to be collected from EGD rate zone ratepayers. The purpose of the
TSDA is to capture the difference between the total ratepayer share of transactional
services revenue and the amount already included in rates.
4. During 2023, the Company generated a total of $ 59.5 million in net Transactional
Services revenue, of which the ratepayer portion represents $ 53.6 million, through a
combination of Storage and Transportation Optimization. Exhibit D, Tab 1, Schedule
2 provides a breakdown of Transactional Services revenue by type of transaction,
and sets out the details of the amount, $41.7 million, proposed to be credited to
customers through the disposition of the 2023 TSDA. For comparison purposes, the
schedule also includes amounts recorded in the applicable TSDA accounts for years
2022, 2021, 2020, and 2019.
Filed: 2024-05-31
EB-2024-0125
Exhibit D
Tab 1
Page 3 of 79
Page 206
5. The transactions that Enbridge Gas entered into in 2023 contained the three
elements of Transactional Services as were described in the Company’s evidence in
EB-2013-0046 in that they were unplanned, the result of a Third-Party service
request and were available because of temporary surplus capacity. Transactional
services optimization in the Enbridge Gas rate zones is higher than what has been
included in rates due to changing market dynamics. The majority of this increase
results from the increase in the Dawn-Waddington spread. This spread is influenced
by the lack of pipeline infrastructure serving US Northeast markets.
Filed: 2024-05-31
EB-2024-0125
Exhibit D
Tab 1
Page 4 of 79
Page 207
2023 UNACCOUNTED FOR GAS VARIANCE ACCOUNT
EGD RATE ZONE
1. The purpose of the Unaccounted for Gas Variance Account (UAFVA) is to capture
the cost associated with the volumetric variances between the actual volume of
unaccounted for gas (UFG)1 and the OEB approved UFG volumetric forecast. The
UAFVA was established in 2002 as part of the Company’s 2002 Rates proceeding
(RP-2001-0032) in recognition of the need to record gas costs associated with
variances between forecast and actual UFG volumes. This evidence provides details
regarding 2023 balances recorded in the UAFVA.
2. In the EGD Rate Zone, actual UFG was determined to be 79,232 103m3. The
forecast volume of UFG was 106,677 103m3. The variance between actual and
forecasted UFG volumes of 27,445 103m3 resulted in a credit balance of $6.9 million
in the UAFVA, plus interest. Exhibit D, Tab 1, Schedule 3 provides the detailed
calculations of the UAFVA balance.
3. Table 1 provides historical UFG volumes for the EGD Rate Zone from 1991 to 2023.
1 “UAF” is the term historically used in reference to distribution related gas losses in the EGD rate zone.
All references to unaccounted for gas will be harmonized to be “UFG” effective January 2024, as
described in the Company’s 2024 Rebasing Application, EB-2022-0200, Exhibit 4, Tab 3, Schedule 1.
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Exhibit D
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Table 1
Historical UAF Volumes for EGD Rate Zone
Line
No.
Calendar Year UAF Volumes (103 m3)
1 1991 40,662
2 1992 66,028
3 1993 49,782
4 1994 108,765
5 1995 90,655
6 1996 56,739
7 1997 65,228
8 1998 116,376
9 1999 108,201
10 2000 132,021
11 2001 75,606
12 2002 9,284
13 2003 21,412
14 2004 -22,406
15 2005 14,815
16 2006 10,274
17 2007 83,823
18 2008 44,424
19 2009 110,917
20 2010 72,104
21 2011 73,355
22 2012 74,762
23 2013 97,361
24 2014 135,380
25 2015 88,438
26 2016 133,112
27 2017 93,077
28 2018 142,086
29 2019 140,594
30 2020 110,234
31 2021 115,553
32 2022 256,333
33 2023 79,232
4. Figure 1 shows historical UFG volumes for the EGD Rate Zone from 1991 to 2023
and includes the 2018 OEB-approved UFG volume forecast.
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Exhibit D
Tab 1
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Page 209
5. In the Settlement Proposal for the Company’s 2022 Deferral and Variance Account
and Earnings Sharing proceeding (EB-2023-0092),2 Enbridge Gas agreed to
address the following items in the current Application:
Detailed evidence will be filed about the items learned and future plans arising from
the ongoing review and investigation of UFG (see Exhibit I.Staff.6), including
(without limitation):
the work completed by Enbridge Gas during 2023 and 2024 and the resulting
observations and learnings,
the impact on UFG from “no bill” customers / volumes that are later billed,
the role, if any, played by Linepack in transmission and other high pressure
systems in the incidence and determination of UFG, and
the Company’s investigation plan for assessing fugitive emissions.3
6. Accordingly, to support the relief sought by Enbridge Gas and to satisfy
commitments previously made regarding UFG volumes, Enbridge Gas is providing
additional detail surrounding recent learnings and observations made regarding
UFG, the impact of No Bills and transmission and high-pressure system Linepack on
UFG, and the Company’s Fugitive Emissions Measurement Project. The additional
2 EB-2023-0092, OEB Decision on Settlement Proposal and Rate Order, February 6, 2024, p.4.
3 As agreed in the EB-2022-0200 Settlement Proposal, Exhibit O1, Tab 1, Schedule 1, June 28, 2023,
pp.36-37.
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Exhibit D
Tab 1
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detail broadly applies to all rate zones unless otherwise indicated and is organized
as follows:
Section 1: UFG-related Works, Observations, and Learnings
Section 2: Impact of No Bill Customer Volumes on UFG
Section 3: Impact of Transmission & Other High-Pressure System Linepack on UFG
Section 4: The Fugitive Emissions Measurement Plan Project
7. In all instances set out below, it is important to consider the relative range of
uncertainty associated with any estimated volumetric impacts (e.g., the accuracy of
measurement assets, estimated volumetric gas losses or emissions, etc.).
Additionally, any quantification set out below carries a degree of uncertainty that
must be considered when evaluating the magnitude of impacts to UFG.
8. As detailed in Section 3.3, Enbridge Gas is also seeking OEB approval to establish a
Fugitive Emissions Measurement Administration Deferral Account (FEMADA) to
record administrative costs associated with the implementation of the Company’s
fugitive emissions investigation plan.
Section 1: UFG-related Works, Observations and Learnings
Section 1.1 – Background
9. As discussed in the Company’s 2022 Deferral and Variance Account Clearance
Application (EB-2023-0092), in response to the elevated levels of UFG experienced
in 2022, Enbridge Gas has taken the initial steps to establish a team with the
express mandate to investigate root causes, make recommendations to reduce and
monitor, and to implement a sustainment and governance model for UFG for the
utility. Since initially filing its evidence in that proceeding, two subsequent settlement
negotiations have focused the Company’s efforts and strategic trajectory in this
regard:
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Exhibit D
Tab 1
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(i) On July 12, 2023, the Company filed a partial Settlement Proposal for its
2024 Rebasing Application that included a novel harmonized regulatory
mechanism to recover UFG costs for all rate zones effective January 2024.4
This mechanism further incents the Company to reduce both overall UFG
volumes relative to approved forecast and inter-year volatility of UFG
volumes. Enbridge Gas also agreed to determine and report on an
appropriate way to identify, measure, and mitigate fugitive emissions and to
file a robust investigation plan for consideration and determination as part of
the current Application (see Section 4 for additional detail). The OEB
accepted the Settlement Proposal on August 17, 2023.5
(ii) On November 28, 2023, the Company filed a Settlement Proposal for its
2023 Deferral and Variance Account Clearance Application that included a
commitment to investigate the impact of No Bill customers/volumes that are
later billed on UFG and to investigate the role of Linepack in transmission
and other high-pressure systems in the incidence and determination of
UFG.6
10. Accordingly, Enbridge Gas began preparation of analysis and evidence relating to
the above changes and commitments. Learnings and observations made regarding
recent investigations into the impact of No Bills, and high-pressure pipeline system
Linepack on UFG are addressed in Sections 2 and 3, respectively. The existing
systems and processes underlying derivation of UFG balances, including No Bills
and Linepack, are complex in nature so the Company is providing additional
foundational explanation and illustrative examples to assist with understanding.
11. As noted in response to interrogatories in the Company’s 2023 Deferral and
Variance Account Clearance proceeding, as of October 31, 2023, a manager was
selected to determine resource requirements to support these efforts. As of Q1
4 EB-2022-0200, Updated Settlement Proposal, July 12, 2023, pp. 11, & 36-37.
5 EB-2022-0200, OEB Decision on Settlement Proposal, August 17, 2023.
6 EB-2023-0092, Settlement Proposal, November 28, 2023, pp. 19-20.
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Exhibit D
Tab 1
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2024, resources have been allocated and the long-term scope of the UFG initiative
remains consistent with the Project Charter previously filed with the OEB.7
Section 1.2 – Benchmarking
12. The 2019 Report on Unaccounted for Gas prepared by ScottMadden Management
Consultants filed in the Company’s 2020 Rates Application (EB-2019-0194) (the
2019 UFG Report) included a UFG Benchmark Analysis for the period of 2008 to
2017. Based on the results of the analysis completed, ScottMadden noted that from
2008-2017 Enbridge Gas had demonstrated lower average UFG volumes than
comparative gas utilities.8
13. For the purposes of the current Application, Enbridge Gas gathered the most current
publicly available data for the same comparative gas utilities (up to and including
2022 for comparative utilities and 2023 for the Company) and updated the
benchmark analysis set out in the 2019 UFG Report.9 Figure 2 reflects the best
available data regarding UFG volumes for each of the comparative utilities. To put
these volumes into perspective, total system UFG in 2023 amounted to
approximately 201,845 103m3 (79,232 103m3 in the EGD Rate Zone and 122,613
103m3 in the Union Rate Zones) compared to total system throughput for that same
year of approximately 56,645,986 103m3 (0.36%).
7 EB-2023-0092, Exhibit I.STAFF.6, Attachment 1.
8 EB 2019-0194, Report on Unaccounted for Gas, December 19, 2019, pp. 3-4.
9 Refer to EB 2019-0194, Report on Unaccounted for Gas, page 15 for details regarding comparative
utilities included in Benchmark Analysis.
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EB-2024-0125
Exhibit D
Tab 1
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Figure 2: UFG Benchmark Analysis
14. Figure 2 demonstrates that all utilities included in the benchmark analysis
experienced similar volatility in UFG over the period from 2008-2022, with material
increases recorded in any one year generally reversing in subsequent years. This
was the case for Enbridge Gas’s UFG volumes in 2022 compared to those
experienced in 2023. As noted in its most recent Decisions regarding UFG costs and
related rate riders for AltaGas and ATCO, the Alberta Utilities Commission stated: 10
In prior decisions, the Commission recognized that UFG is an expected
element of operating a natural gas distribution system. The Commission also
recognized that, due to the many factors that impact UFG, the UFG amount
will fluctuate over time.
10 Alberta Utilities Commission, Decision 27552-D01-2022 (September 12, 2022), 2022-2023
Unaccounted-For Gas Rider E and Rider H. (Apex Utilities Inc.), pp. 2-4; and Alberta Utilities
Commission, Decision 28406-D01-2022 (October 17, 2022), 2023 Unaccounted-For Gas Rider D and
Rider P. (ATCO Gas and Pipelines Inc.), pp. 2-4.
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Exhibit D
Tab 1
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15. Figure 2 reflects certain industry-wide trends across comparative utilities, such as a
general decline in UFG volumes recorded in each of 2014, 2015 and 2020 followed
by increases in UFG volumes recorded in subsequent years. Importantly, nearly all
comparable utility groups set out in Figure 2 also experienced a significant increase
in UFG volumes in 2022. It is reasonable to assume that such trends in UFG
volumes or related trends in UFG costs may be reflective of common macro-
economic, geo-political, and/or national/continental weather trends, which have the
potential to impact UFG volumes or costs broadly across the industry. Such trends
highlight the value of comparing UFG volumes and costs experienced by a single
utility to relevant peer groups over time.
16. Finally, Figure 2 also shows that the EGD and Union Rate Zones’ UFG volumes and
annual fluctuations are generally consistent with other gas utilities. It also
demonstrates that while Enbridge Gas has experienced recent increases in UFG
volumes in the Union Rate Zones (2021) and in the EGD Rate Zone (2022), UFG
volumes for 2023 were far lower in all rate zones.
Section 1.3 – Derivation of Balances
17. Throughout 2023 and 2024, Enbridge Gas assessed many complex systems and
processes that contribute to the derivation of UFG balances. The details set out
within this section of evidence serve to educate and inform the reader of those
relevant systems and processes and to provide the necessary foundation to support
understanding of the topics discussed within subsequent sections of evidence. This
section of evidence describes the Company’s processes and methodologies to
derive annual UFG volumes and to calculate resulting balances in UFG-related
variance accounts for the EGD Rate Zone and the Union Rate Zones. More
specifically, this section describes how the Company’s UFG Forecast is determined,
and the monthly and annual processes for determining actual UFG volumes.
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Exhibit D
Tab 1
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Determination of UFG Forecast –
EGD Rate Zone
18. The current method to forecast UFG volumes in the EGD Rate Zone estimates the
relationship between historical calculated UFG and the total historical
unlocked/active customers based on the presumption that UFG volume is directly
correlated to the scale of the distribution system.
19. Historically, the UFG volume forecast was updated annually and approved by the
OEB as part of the Company’s annual rate setting proceedings. Since the
amalgamation of EGD and Union, the UFG volume forecast for the EGD Rate Zone
has been fixed at the level approved by the OEB as part of the Company’s 2018
Rates proceeding (EB-2017-0086) of 106,677 103m3. The OEB-approved UFG
volume forecast is an annual amount, which is split into monthly volumes in
proportion to the monthly profile of forecasted total throughput for the EGD Rate
Zone.
Union Rate Zones
20. The current methodology to forecast UFG volumes in the Union Rate Zones is
based on calculating a 3-year weighted average of the ratio of UFG volumes to total
system throughput. The ratio of UFG volumes to total system throughput is
weighted, where the most recent year has a weighting of 3:6 (50%), the second
most recent year has a weighting of 1:3 (33%), and the third most recent year has a
weighting of 1:6 (17%).
21. The ratio of UFG volumes to total system throughput used to forecast UFG volumes
for the period of 2013 to 2023 of 0.219% was established based on the weighted
average of actual UFG and total system throughput volumes from 2009-2011.11 This
OEB-approved ratio is multiplied by the annual total system throughput forecast for a
given year to derive an annual forecast of UFG volumes. Similarly, the UFG volume
11 As approved by the OEB as part of Union’s 2013 Cost of Service Application - EB-2011-0210, Exhibit
D3, Tab 2, Schedule 2, Updated; EB-2011-0210, OEB Decision and Order, October 24, 2012.
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Exhibit D
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currently included in rates is calculated by multiplying the 0.219% ratio by the 2013
OEB approved forecast total system throughput volumes.
2024+ Harmonized Methodology
22. Effective January 1, 2024, Enbridge Gas will rely upon a consolidated OEB-
approved methodology to forecast annual UFG volumes across all rate zones,
based on the average annual actual UFG volumes calculated for all rate zones from
2018-2020 of 243,681 103m3.12
Determination of Actual UFG – Monthly Processes
23. For the purposes of deriving UFG-related costs, UFG volumes are calculated by
determining the difference between net gas sendout volumes (Sendout) and actual
in-franchise customer consumption volumes (Consumption). In a theoretical system
with no UFG, Sendout volumes would match Consumption volumes.
Sendout
24. Sendout is the net volume of natural gas delivered into the Enbridge Gas distribution
system to serve in-franchise customer demands after accounting for receipts and
deliveries across Enbridge Gas’ integrated storage, transmission, and distribution
systems.
25. Receipts are the volumes of gas received into the distribution system from various
interconnects and measured via custody transfer measurement, including:
ex-franchise transmission pipelines,
local Ontario production (Producers), from traditional natural gas production
wells and renewable natural gas (RNG), as well as hydrogen,
net withdrawals from Ontario storage pools, and
injections into the distribution system from liquified natural gas (LNG) and
compressed natural gas (CNG) facilities.
12 EB-2022-0200, Partial Settlement Proposal, Exhibit O1, Tab 1, Schedule 1, June 28, 2023, p. 37.
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Exhibit D
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26. Deliveries are the volumes of gas delivered by Enbridge Gas from its integrated
storage, transmission, and distribution systems to various interconnects and
measured via custody transfer measurement, including:
ex-franchise transmission pipelines,
net injections into Ontario storage pools,
injections into LNG and CNG facilities,
Company use fuel (e.g., line heaters, space heating, etc.), and
Company blowdown gas (i.e., an estimate of volumes typically purged or
flared for operational maintenance purposes).
27. At custody transfer points, there is custody transfer measurement and often check
measurement both of which utilize Measurement Canada approved equipment.13
Custody transfer measurement, as it is the official system of record for billing
purposes, is required to comply with Measurement Canada’s +/- 3% overall volume
measurement error tolerance.14
28. Further, Enbridge Gas operates within more stringent measurement error
tolerances. The Company maintains up to a +/- 1% measurement error tolerance for
testing and sealing a meter within a controlled test environment. Enbridge Gas
investigates any monthly volume variance between custody transfer and check
metering volumes that exceeds +/- 2%. Enbridge Gas has established manual and
automated means by which to validate measurement accuracy and takes volumetric,
energy content, temperature, and pressure factors/variables into consideration when
investigating measurement variances compared to prescribed reasonability
tolerances, in addition to validating measurement completeness. It is important to
consider such measurement error tolerances together with other uncertainties when
13 Check measurement is not required to comply with Measurement Canada’s standards.
14 At custody transfer points where gas is delivered to the Company, the interconnecting operator (third-
party) has custody transfer measurement while Enbridge Gas often has check measurement. Ownership
of measurement is reversed at custody transfer points where Enbridge Gas delivers gas to an
interconnecting operator (third party). A small number of exceptions to this rule exist wherein Enbridge
Gas regularly analyzes and validates sole source measurement data for consistency to ensure a
consistent “quality” of information across all custody transfer points.
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Exhibit D
Tab 1
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assessing contributing sources of actual UFG volumes observed annually (0.36% for
2023 as discussed in Section 1.0).
Consumption
29. The nature of available customer Consumption data, whether it is measured or
estimated and whether it is billed or not billed, impacts the calculation of UFG. In
general, the Consumption volumes used in the calculation of UFG include both billed
Consumption and unbilled Consumption. Billed Consumption volumes are sourced
from the billing system and interfaced to the financial accounting system. Unbilled
Consumption volumes are calculated and recorded within the financial accounting
system only.
30. Consumption is billed monthly and is calculated within the billing system based on a
combination of actual and estimated meter reads. Most contract rate customers
have actual daily measurement recorded, using telemetry devices (see Section 1.4
for additional discussion of the nature of telemetry for contract rate customers),
which is used to calculate their billed Consumption. The remaining customers, which
are mainly residential and small commercial customers, have periodic meter reads
completed and rely on a combination of actual and estimated meter reads to
calculate their billed Consumption. Estimated meter reads are calculated for each
customer based on the Consumption history for their respective premises. When
insufficient Consumption history exists to derive an accurate estimated meter read,
the billing system uses a combination of heating degree day data (HDD) and
standard factors, depending upon the nature of the customer and premises, to
derive an estimate.
31. In instances where a customer’s billed Consumption is based on an estimated meter
read, a subsequent true up will occur once an actual meter read is next recorded.
After obtaining an actual meter read, Enbridge Gas performs a volumetric billing
adjustment by allocating the Consumption over the estimated period using HDDs,
the number of days in each billing period, and the customer’s actual Consumption
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Exhibit D
Tab 1
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for the same period in the prior year.15 In situations where the customer’s
Consumption pattern varies by season, Enbridge Gas works with the customer to
understand the nature of their Consumption. When a volumetric adjustment spans
more than a single fiscal quarter, the Company also ensures that the appropriate
quarterly QRAM rate is applied to consumed volumes. See the example set out in
Table 2 for the accounting treatment of an illustrative Estimated Meter Read
scenario:
15 Re-allocation of volumes to previous months are completed in following with Enbridge Gas policy as
required under section 7.3.2 of GDAR.
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Exhibit D
Tab 1
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Table 2
“Estimated Meter Read” Example
Line
No. Particulars (units of Consumption) Month 1 Month 2
(a) (b)
1 Sendout 100 100
Billed Consumption
2 Estimated Read 95 -95
3 Actual Read 0 200
Finance Estimate
4 No Bills 0 0
5 Unbilled 0 0
6 Total Consumption (Billing + Finance) (lines 2 + 3 + 4 + 5) 95 105
7 Monthly UFG (line 1 - 6) 5 -5
8 Cumulative UFG (1) 5 0
Notes: (1)
Cumulative UFG for Month 1 equals line 7 column (a). Cumulative UFG for
Month 2 equal line 7 column (a) plus line 7 column (b).
32. The billing system ensures that any volumetric billing adjustment to the customer
applies the appropriate QRAM rate for the period in which Consumption occurred.
To the extent that a volumetric billing adjustment is recorded, it is reflected in the
financial accounting system in the period in which the final billing adjustment
ultimately occurred.
33. Consumption volumes for the purposes of calculating UFG also includes an
estimation of gas consumed but not yet billed (unbilled Consumption). This includes
customers who are billed on a staggered schedule throughout the month (Cycle
Billed) as well as customers who have not been issued a bill in a specific accounting
period (referred to as “No Bills”).
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Exhibit D
Tab 1
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34. Cycle billing is a common industry practice whereby customers are billed based on a
schedule that is staggered throughout the month rather than billing all customers on
the same date. As a result of cycle billing, a portion of customer Consumption at any
point in time has not been billed. Figure 3 provides an illustrative example of the
Company’s cycle billing practices. In this instance, for the calendar month of
December, the yellow-highlighted portions of cycles 1-21 represent Consumption
that occurred within the month of December and that will be billed within that same
month. The orange-highlighted portions of cycles 1-21 represent Consumption that
occurred within the month of December and that will be billed in the following month
(January).
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Exhibit D
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Figure 3: Graphical Depiction of Cycle Billing 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 262728293031123456789101112131415161718192021NOVEMBERDECEMBERJANUARY DayCycleBilledUnbilledBilledUnbilledFiled: 2024-05-31 EB-2024-0125 Exhibit D Tab 1 Page 20 of 79Page 223
35. To align the reporting of monthly customer Consumption with calendar month
reporting periods for accounting purposes, it is necessary to record an estimate of
gas delivered but not yet billed at the end of every monthly reporting period. This
estimate is recorded in the financial accounting system and is calculated at the rate
class level. This estimate considers factors such as number of customers per billing
cycle, number of days for each cycle which have not been billed, average use per
HDD, actual HDDs, and demand coefficients. The unbilled Consumption estimate
that is recorded in each reporting period in the accounting system is reversed in the
following reporting period and replaced by actual billed Consumption. To the extent
that the estimate of the unbilled Consumption differs from the actual billed
Consumption, a volumetric adjustment is performed and recorded to reflect the
difference. See the example set out in Table 3 for the accounting treatment of an
illustrative Cycle Billing scenario:
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Exhibit D
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Table 3
“Cycle Billed” Example
Line
No. Particulars (units of Consumption) Month 1 Month 2
(a) (b)
1 Sendout 100 100
Billed Consumption
2 Estimated Read 45 -45
3 Actual Read 0 200
Finance Estimate
4 No Bills 0 0
5 Unbilled 50 -50
6 Total Consumption (Billing + Finance) (lines 2 + 3 + 4 + 5) 95 105
7 Monthly UFG (line 1 - 6) 5 -5
8 Cumulative UFG (1) 5 0
Notes: (1)
Cumulative UFG for Month 1 equals line 7 column (a). Cumulative UFG for
Month 2 equal line 7 column (a) plus line 7 column (b).
36. “No Bills” refers to the scenario where a bill has not been issued to a customer in a
given accounting period. In these instances, Enbridge Gas’ financial practice is to
record an estimate of gas volumes delivered but not yet billed, which follows a
process very similar to the “cycle-billed” unbilled estimation process described
above. The No Bills estimate is calculated at the rate class level and recorded within
the financial accounting system. This estimate considers factors such as billing
cycles, number of customers, number of billing periods which have not been billed,
average use per HDD, actual HDDs, and demand coefficients. The No Bills
Consumption estimate that is recorded in each reporting period in the financial
accounting system is reversed in the following reporting period and replaced by
actual billed Consumption. To the extent that the estimate of the Consumption
recorded in the accounting system differs from the actual billed Consumption, a
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Exhibit D
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volumetric adjustment is completed in the financial accounting system and recorded
to reflect the difference. Section 2 provides additional discussion on the incidents of
No Bills, and their impact on UFG volumes.
37. If the estimation of unbilled and No Bills Consumption recorded in the financial
accounting system was determined to be understated, the effect is a temporary
increase to cumulative UFG in the period that the Unbilled and No Bills estimation
was recorded. That same increase to cumulative UFG is then reversed when the
estimate is replaced with actual billed Consumption in a subsequent period. The
inverse is also true. See the example set out in Table 4 for an illustrative No Bills
scenario:
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Exhibit D
Tab 1
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Table 4
“No Bill” Example
Line
No. Particulars (units of Consumption) Month 1 Month 2
(a) (b)
1 Sendout 100 100
Billed Consumption
2 Estimated Read 0 0
3 Actual Read 0 200
Finance Estimate
4 No Bills 80 -80
5 Unbilled
6 Total Consumption (Billing + Finance) (lines 2 + 3 + 4 + 5) 80 120
7 Monthly UFG (line 1 - 6) 20 -20
8 Cumulative UFG (1) 20 0
Notes: (1)
Cumulative UFG for Month 1 equals line 7 column (a). Cumulative UFG for
Month 2 equal line 7 column (a) plus line 7 column (b).
38. Measurement errors also result in a difference between actual and metered
customer Consumption volumes and can be attributable to meter failure, meters that
do not accurately correct for temperature or pressure variations, or Consumption
that is no longer appropriate for the size of meter installed.16 Like adjustments made
to correct billing estimates, to the extent that measurement errors occur and are
quantifiable, a volumetric billing adjustment is performed and recorded to reflect the
difference between actual and metered customer Consumption volumes (see
Sections 1.4 and 2 for further discussion regarding measurement errors).
Measurement errors result in a UFG loss/(gain) in the period when the error occurs
and an equal and offsetting UFG (gain)/loss when a volumetric billing adjustment is
performed and recorded.
16EB-2019-0194, Report on Unaccounted for Gas, December 19, 2019, p. 28.
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Exhibit D
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39. On a monthly basis, the calculation of UFG volumes is recorded based on an annual
forecasted heat value for natural gas delivered to customers.17 In the following
month, when the actual heat values are available, the difference between the actual
and annual forecasted heat value is recorded in UFG deferral and variance
accounts.
40. On a monthly basis, the determination of Sendout includes an entry to record
operational blowdowns or flaring associated with compressor facilities as noted in
the discussion on Sendout above. By accounting for the volumes associated with
these operational blowdowns or flaring, these volumes are removed from Sendout
and as such do not contribute to calculated UFG volumes. A similar entry is
recorded, where necessary, for blowdowns or flaring associated with capital
projects.
41. In summary, the monthly determination of UFG is derived as the difference between
Sendout and Consumption. The residual difference between Sendout and
Consumption represents a combination of actual physical gas losses/gains as well
as temporary variances resulting from estimation used in both the billing and
accounting processes described in this section. The temporary variances are
reversed when the appropriate true ups are recorded in a subsequent accounting
period. The treatment of these true ups when they occur in a subsequent fiscal year
relative to the period of time in which the true ups pertain to is addressed in the next
section.
Determination of Actual UFG – Annual Processes
42. The monthly processes described above are normal course of business for each
monthly accounting reporting period, including the end of the calendar fiscal year.
However, there are additional processes that occur on an annual basis.
17 Heat value is the amount of energy per volume of the natural gas stream. As discussed in Enbridge
Gas’ 2024 Rebasing Application EB-2022-0200, Exhibit 3 Tab 6, Schedule 1, p. 2, conversion of volumes
to energy is required as the natural gas industry measures natural gas transactions in energy units (GJ)
however Enbridge Gas measures consumption in meters cubed (m3).
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Exhibit D
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43. For the EGD Rate Zone, there is an additional step that is completed after the end of
the calendar fiscal year. The current accounting order for the UAFVA states that, “An
adjustment will be made to the UAFVA in the subsequent year to record any
differences between the estimated UFG and actual UFG.”18 In the EGD Rate Zone,
the variance between the unbilled and No Bills estimated consumption recorded in
December and the associated billed Consumption recorded in the following year is
included in the calculation of the UAFVA balance for the fiscal year during which the
unbilled and No Bills estimate(s) were recorded. This ensures that any such
adjustment(s) is recorded in the UAFVA for the reporting period that the
Consumption pertains to and eliminates a timing variance across fiscal years.
44. No such provision to record an adjustment(s) relating to unbilled and No Bills
estimated Consumption across fiscal years exists for the Union Rate Zones or the
associated UFGVDA. As such, to the extent that a variance exists between
estimated Consumption and actual Consumption, any adjustment(s) made after
December will be recorded in the deferral account in the subsequent fiscal year.
45. In its 2024 Rebasing Application,19 Enbridge Gas proposed to harmonize UFG-
related deferral and variance accounts for the EGD and Union Rate Zones into a
single UFG Volume Variance Account (UFGVVA) (Account No. 179-203). Like the
accounting treatment currently applicable to the EGD Rate Zone UAFVDA, the
proposed harmonized accounting order includes a provision enabling the Company
to adjust for differences in estimated UFG and actual UFG to minimize timing
variance(s) across fiscal years for all rate zones. The OEB accepted the Company’s
proposed accounting order and treatment effective January 1, 2024.20
46. There are exceptional circumstances that may occur where true-ups are recorded in
a year subsequent to the period that the consumption pertains to, beyond the timing
18 EB-2019-0194, Exhibit D, Tab 3, Accounting Order, Appendix B, p. 9.
19 EB-2022-0200, Exhibit 9, Tab 1, Schedule 1, Attachment 3, p. 7.
20 EB-2022-0200 Exhibit O1, Tab 1, Schedule 1, pp. 54-55, and EB-2022-0200, OEB Decision and Order,
December 21, 2023.
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that allows for inclusion in the annual adjustment as discussed in the previous
paragraph. Furthermore, the adjustment that is made to the UAFVA is limited to true-
ups associated with unbilled and no bill estimates. As described above, true-ups
also occur in relation to scenarios such as estimated meter reads, billing disputes or
measurement errors. These true-ups are generally referred to as prior period
adjustments (PPAs) and are normal course of business. As an example, a delayed
meter reading would result in consecutive estimates, which is not trued-up until the
actual meter read ultimately takes place. If the actual read and associated true-up
occurs in a different fiscal year than the period which the consumption occurred, the
true-up has the effect of impacting the current year UFG volumes. As UFG volumes
are recorded in the respective deferral/variance accounts and are disposed of, the
appropriate customers and rate classes are allocated a portion of the relevant UFG
deferral/variance account based on OEB approved allocation methodologies. If a
PPA associated with those volumes is recorded in a subsequent fiscal year, the PPA
would result in a corresponding offsetting impact to the relevant deferral/variance
account balance in that year and would subsequently be disposed of in the same
manner keeping ratepayers whole.
47. On an annual basis, an adjustment is made to remove monetary recoveries of gas
loss amounts resulting from third-party damages from the UAFVA balance for the
EGD rate zone. No similar adjustment is made for the UFGVA for the Union rate
zones. See section 1.4 for further detail on the harmonization of gas loss
calculations and harmonization of treatment of gas loss damage recoveries within
the harmonized UFGVVA starting in 2024.
48. Each year for the Union Rate Zones, the Company allocates UFG to its unregulated
business(s) based on gross unregulated storage activity as a percentage of total
actual gross storage and transportation activity. This ensures that no costs or
volumes associated with unregulated business activities are included in the amounts
recorded in the UFGVDA.
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49. For the EGD Rate Zone, the Company recovers UFG volumes and costs relating to
storage operations volumetrically in delivery rates based on a fixed OEB-approved
provision, and no variances are recorded in a variance account. An allocation of
storage related UFG volumes is made to unregulated storage operations, using a
capacity-based allocation, as determined in EGD’s 2016 Rate Application.21
50. A detailed description of the current methodology and a modified methodology
proposed to become effective January 1, 2024, was filed as part of the Company’s
2024 Rebasing Application and is being reviewed by the OEB as part of Phase 2 of
that proceeding.22
51. Enbridge Gas also undergoes an annual audit of storage inventory to identify
inventory variances as described in Section 1.4. In the Union Rates Zones,
adjustments to inventory resulting from the storage inventory audit are recorded in
the UFGVDA. In the EGD Rate Zone, as described above, the Company recovers
UFG volumes and costs related to storage operations based on a fixed OEB-
approved provision, and no variances are recorded in a variance account.
Adjustments to inventory from the storage inventory audit in the EGD Rate Zone are
not recorded in the UAFVA, which recovers distribution related gas losses only. As a
single harmonized UFGVVA was approved as part of the Company’s 2024 Phase 1
Rebasing proceeding, adjustments to inventory resulting from storage inventory
audits for both legacy rate zones will be recorded in the UFGVVA as of 2024.
21 EB-2015-0114, Settlement Agreement, Exhibit N1, Tab 1, Schedule 1, December 1, 2015, pp.14-15.
22 EB-2024-0111, Phase 2 Exhibit 1, Tab 13, Schedule 2.
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Section 1.4 – 2023/2024 UFG Learnings and Observations
52. In response to interrogatories in its 2023 Deferral and Variance Account Clearance
proceeding, the Company described several recent and ongoing initiatives with the
potential to provide insights into UFG volumes experienced or potential UFG
mitigation activities.23 Despite the recent adjusted priorities of the UFG team
described above, some further progress has been made to better understand the
implications of those recent and ongoing initiatives, to assess the materiality of
certain known contributing sources of UFG, to mitigate certain known contributing
sources of UFG, and to identify additional potential contributing sources of UFG for
future investigation and mitigation.
Participation in Industry Groups/Associations, & Cross-Functional Measurement
Groups
53. As discussed in the Company’s 2024 Rebasing application and associated UFG
Progress Report,24 the Company is continuing its work with interconnecting pipelines
through participation in industry associations and remains focused on increasing
internal cross-functional collaboration related to measurement.
54. In terms of its participation in Industry Groups and Associations, representatives of
Enbridge Gas participate in the Canadian Gas Association’s Measurement &
Regulation Committee and Steering Group as well as its Gas Process Advisory
Committee which is chaired by Measurement Canada. Enbridge Gas and other
industry stakeholders also meet regularly with Measurement Canada, as part of
various working groups, to support revisions to Measurement Canada’s
specifications with the goal of increasing measurement accuracy across the industry.
In 2023, the Company supported revisions to the specifications for compliance
sampling used for seal extension and is currently working with Measurement
23 EB-2023-0092, Exhibit I.STAFF.6, p. 2.
24 EB-2022-0200, Exhibit 4, Tab 3, Schedule 1, p. 20, and Attachment 3. p. 15.
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Canada on pressure factor metering (PFM) specifications modernization and on
specifications for ultrasonic meters.
Work to Update Gas Quality Parameters
55. As discussed in the Company’s 2024 Phase 1 Rebasing application and associated
UFG Progress Report and Supplemental UFG Progress Report, in 2020 the
Company initiated a project to address outdated and non-representative gas quality
parameters in more than 6,000 electronic volume corrector (EVCs) devices across
the EGD Rate Zone.25 Whereas EVCs in the Union Rate Zones were historically
(since 2002) periodically updated, EVCs in the EGD Rate Zone were found to not
have been updated to reflect the characteristics of the current natural gas supply mix
entering Ontario, resulting in undercalculation of supercompressibility,26 under
measurement of volumes, and unaccounted for gas volumes.27 At the time, Enbridge
Gas concluded that the impacts of reliance on outdated gas quality parameters
could have resulted in undermeasurement of volumes, which would have contributed
to UFG volumes/costs recorded for the EGD Rate Zone, ranging from 0.05% at 60
psig to 0.67% at 700 psig, resulting in estimated potential annual volumetric impacts
of approximately 2,116 103m3.28
56. As of June 2019, all new EVC installations are made with updated parameters. As of
the date of this filing, more than 6,000 EVCs have been updated. The Company
expects that all remaining EVCs in the EGD Rate Zone will be configured with more
25 EB-2022-0200, Exhibit 4, Tab 3, Schedule 1, Attachment 3, pp. 13-14. Please also see the response at
EB-2022-0200, Exhibit I.4.3-FRPO-153.
26 Supercompressibility factor is a factor to compensate for the compressibility of the flow gas, what is
sometimes termed the deviation from Boyle’s law. The factor is derived based on compressibility factors
of the gas at base pressure and at flow conditions. (U.S. National bureau of Standards)
27 Conversion of natural gas volumes from line conditions to standard conditions (101.325 kPa and 15 ˚C)
requires a supercompressibility correction via a supercompressibility factor applied in the field via EVCs
and remote terminal units (RTUs) to obtain accurate values of natural gas volume. Enbridge Gas uses the
NX-19 method to calculate supercompressibility, which requires measures of specific gravity, N2
concentration, and CO2 concentration.
28 More precise calculation would require comparison of results through meters for both historic and
updated parameters using exact replication of real-time historic flows, atmospheric pressures, and gas
temperature.
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representative gas quality parameters by 2025 through the course of routine
pressure regulation and measurement inspections. Going forward, gas quality
parameters will be updated at a minimum on a 5-year cycle (for those with a lower
maximum operating pressure (MOP) and flow rate) and as frequently as annually
(for those with a higher MOP and flow rate). Further, the Large Volume
Measurement Integration initiatives described below (namely the deployment of new
measurement systems) are expected to improve the Company’s ability to manage
supercompressibility parameters as it will be possible to adjust them over-the-air
(remotely).
Work to Eliminate a Backlog of Leaks
57. As discussed in the Company’s 2024 Phase 1 Rebasing application and associated
UFG Progress Report, in 2021 the Company initiated a project to eliminate 3,274
class-C leaks identified within the Union Rate Zones following the integration of
Union and EGD.29 The project was completed on December 31, 2023, and was
successful in resolving all identified leaks either via repair (1,563 instances), close-
out (1,701 instances),30 or request for variance (10 instances of outstanding leaks).
The Company intends to mitigate the 10 outstanding leaks that currently remain as
part of planned replacement works over the course of 2024 and 2025. Going
forward, all class-C leaks will be monitored every 12 months and will be repaired
within 18 months of discovery, in accordance with the new integrated Enbridge Gas
Leak Standard.
58. At this time, the Company does not measure flow rates from leaks within the
distribution system and is not able to accurately estimate the actual impact of the
backlog of leaks on calculated annual UFG volumes. However, using published
29 Union had previously maintained an operating standard that required class-C leaks to be monitored
every 12 months (if not otherwise repaired) to ensure that they did not progress to more sever class-A or
class-B leaks that required more urgent mitigative action. Class-C leaks are defined as, a leak on any
non-plastic asset that is nonhazardous at the time of detection and can be reasonably expected to remain
nonhazardous.
30 Certain of the leaks closed out included duplicative reported leaks or data errors that were
subsequently investigated and resolved.
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industry-average emission factors as prescribed by the provincial and federal GHG
reporting programs, it is estimated that the reduction of the backlog of leaks has
resulted in a reduction in the annual loss of natural gas of approximately 1,100
103m3. As discussed in Section 4, Enbridge Gas has initiated the Fugitive Emissions
Measurement Plan Project to develop an investigation plan to quantify fugitive
emissions more accurately.
Various Meter Reading Campaigns & Initiatives
59. In 2019, a key meter reading vendor terminated its service contract with Enbridge
Gas, resulting in the need to hire a new vendor. The impacts of this issue persisted
into 2020 and 2021 as the new vendor continued to learn Enbridge Gas’s unique
business requirements, dealt with extreme weather events (freezing rain, polar
vortex, heavy snowfall, and flooding, all of which impacted access to certain
properties), and struggled to maintain service standards and staffing levels
throughout the COVID-19 pandemic due to events beyond the Company’s control,
including closed businesses and storefronts, and increased customer opposition to
providing physical access to premises.31
60. As noted in Enbridge Gas's 2024 Phase 1 Rebasing evidence, as of the time of that
filing (September 2022) the Company had initiated a variety of campaigns to
improve meter reading frequency and efficiency, including:32
Consecutive estimate campaign – working with meter reading vendors to
hire additional readers and conduct meter reading and communication
campaigns.
Inbound calls – educating customers on the importance of providing access
to meters and aiding them to read their own meters.
31 Enbridge Gas was required to follow Public Health guidelines during the COVID-19 pandemic, including
observation of lockdown, quarantine, and social distancing requirements. During periods of lockdown,
Enbridge Gas faced several challenges with meter reading and directed its meter reading partners to
ensure that all staff were working as safely as possible, and to avoid close contact with the public and
customers.
32 EB-2022-0200, Exhibit 1, Tab 7, Schedule 1, pp. 10-14 and Exhibit 1, Tab 7, Schedule 1, Attachment 4.
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Customer outreach – targeted customer communications to engage
customers to arrange for meter access and submit own meter reads
(including incentive programs).
Meter reading processes – review and continuous improvement to increase
attainment and efficiency.
Since that time, Enbridge Gas has seen significant improvements in meter reading
frequency, as noted in Exhibit G, having reduced the proportion of meters with no
read for 4 months or more from 5.0% in 2021 to 1.3% in 2023. Similarly, the
Company’s annual meter reading performance (MRP), a measure of total planned
vs. actual meters read,33 increased from 89.6% for 2022 to 93.7% for 2023.
61. As discussed in greater detail in Section 1.3, improvements in meter reading
frequency reduce the Company’s reliance on estimated customer Consumption and
related temporary variances in the billing and financial reporting processes.
Vacant Premises Backlog
62. According to Enbridge Gas’s Conditions of Service,34 customers are required to
notify the Company before taking possession of a new home, otherwise the
premises are considered to be vacant and eligible for discontinuance of service. In
this context, vacant premises encompass properties with existing natural gas service
and an existing customer account that is sold or vacated, which continue to
consume natural gas and for which no new customer account is established.
63. As previously noted in response to interrogatories in Enbridge Gas’s 2023 Deferral
and Variance Account Clearance proceeding, the Company is continuing its work to
resolve a backlog of vacant premises that accumulated over the course of the
COVID 19 pandemic.35 Whereas under normal circumstances Enbridge Gas would
33 MRP relates to general service customer classes (e.g., Rates 1, 6, 10, & M2) and does not include
large volume telemetered customers.
34 https://www.enbridgegas.com/en/conditions-of-service
35 EB-2023-0092, Exhibit I.STAFF.6, p. 2.
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discontinue services to such premises via lockout at the customer meter after
warning the property owner in advance, the Company temporarily halted all such
lockouts beginning in 2020 for safety reasons related to the ongoing COVID-19
pandemic and to provide exceptional relief to customers made economically
vulnerable.36 The Company only recommenced lockouts for non-compliance in Q2
2023.
64. In instances where vacant premises cases weren’t resolved within the fiscal
calendar year, as the Company has not historically estimated or accrued volumes for
such circumstances, Enbridge Gas presumes that they may have contributed to
UFG volumes. The number of such vacant premises with the potential to have
caused intra-period UFG volatility (i.e., via billing adjustments in subsequent fiscal
periods) increased beginning in 2020 from historic levels. For context, Table 5
contains the historic number of lockouts issued for vacant premises from 2018 to
2023 and reflects a sharp decrease beginning in 2020, consistent with the timing
and circumstances discussed above.
Table 5
Historical Vacant Premises Lockouts
Line
No.
Year No. of Vacant Premises Lockouts
1 2018 3,504
2 2019 9,465
3 2020 809
4 2021 7
5 2022 813
6 2023 3,589
65. At this time, the Company is not able to accurately estimate the actual impact that
vacant premises had on UFG volumes recorded given the need to investigate the
circumstances of each instance to understand its duration and to develop a unique
and accurate Consumption estimate. However, since recommencing its normal
36 EB-2022-0200, Exhibit 4, Tab 4, Schedule 2, p. 29.
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warning notice and lockout procedures in Q2 2023 (with a focus on resolving the
longest duration and highest potential Consumption instances), and by leveraging
property ownership search functionality available via GeoWarehouse,37 Enbridge
Gas has resolved approximately 6,800 instances of vacant premises as of the date
of this filing.
66. The Company recommenced seasonal lockouts associated with vacant premises in
2024 on May 1 and is targeting to achieve 200% more locks than 2023 between May
and October until the earlier of all outstanding cases are resolved or the
commencement of 2024/2025 winter season (when customer lockouts are halted).
Additionally, seasonal resources have been assigned to complete GeoWarehouse
searches on lower consumption premises and premises with inside meters. Through
the initiatives described above, Enbridge Gas expects to return to pre-pandemic
lockout levels by 2025. Enbridge Gas also intends to investigate the viability of
developing a process in 2024 to report annually on vacant premises instances,
estimate their respective Consumption, and accrue for that Consumption at year-end
(like the processes for unbilled estimates described in Sections 1.3 and 2). Together,
these activities are expected to improve the Company’s understanding of and to
mitigate the impact of vacant premises in the future.
Assessment of Storage Inventory Audits and Adjustments
67. As discussed in response to interrogatories in the Company’s 2024 Phase 1
Rebasing proceeding,38 inventories in all Enbridge Gas storage pools are monitored
via observation wells (for pressure) and custody transfer quality measurement (for
volumetric flows). Following spring and fall stabilization periods, which allow
pressures to equalize across storage reservoirs, an audit of inventories is routinely
conducted to identify inventory variances. Variances in inventories are typically
37 GeoWarehouse is the single source of authoritative property information in Ontario. Subscribers can
verify property ownership information by searching an address in GeoWarehouse. Enbridge Gas uses
this to verify owner information during winter months in order to avoid service disruptions during this time.
38 EB-2022-0200, Exhibit I.4.3-FRPO-150.
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attributable to measurement error or natural gas migration within a storage reservoir.
Adjustments are made to inventories based on the results of these audits. All such
adjustments and related inventory analysis are reviewed by an external auditor on
an annual basis. Additional detail regarding the accounting treatment of storage
inventory adjustments, including their impact on UFG, is discussed in Section 1.3.
68. In 2023, Enbridge Gas reviewed the process for tracking, adjusting, and auditing
storage inventories and found that total adjustments to underground storage
inventories made in 2021, 2022 and 2023 were not a material source of UFG for
Enbridge Gas. This conclusion is supported by the data set out in Table 6, which
contains details of all historical adjustments to storage inventories made from 2002
to 2023.
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Table 6
Storage Pool Inventory Adjustments
Union Rate Zone EGD Rate Zone
Adjustments Percentage Adjustments Percentage
Line
No. Year (103m3) (%) (103m3) (%)
(a) (b) (c) (d)
1 2002 8,677 0.21% 0 0.00%
2 2003 17,458 0.43% 0 0.00%
3 2004 0 0.00% 0 0.00%
4 2005 -8,055 -0.20% 0 0.00%
5 2006 0 0.00% 0 0.00%
6 2007 0 0.00% 0 0.00%
7 2008 0 0.00% 0 0.00%
8 2009 -11,751 -0.28% 0 0.00%
9 2010 -23,196 -0.56% 0 0.00%
10 2011 6,669 0.16% 0 0.00%
11 2012 20,621 0.49% -54,209 -1.73%
12 2013 -747 -0.02% 0 0.00%
13 2014 -20,218 -0.48% 0 0.00%
14 2015 120 0.00% 0 0.00%
15 2016 5,168 0.12% 0 0.00%
16 2017 0 0.00% 0 0.00%
17 2018 1,652 0.04% -60,225 -1.85%
18 2019 0 0.00% -13,746 -0.42%
19 2020 0 0.00% 0 0.00%
20 2021 -2,601 -0.06% 0 0.00%
21 2022 -2,834 -0.06% -1,116 -0.03%
22 2023 4,853 0.11% 0 0.00%
Notes:
1 'Negative sign indicates that measured inventory was reduced.
2
Adjustments can be attributed to either
measurement error or a change in the
reservoir index.
3 EGD meter upgrade project was completed in 2012. 2018/19
adjustments based on 2013-2017 measurements
69. Further, Enbridge Gas has recently drilled and constructed several stratigraphic test
wells and A-1 observation wells. These wells and the associated monitoring
equipment provide further information on the geological properties of the Company’s
underground storage pools. Additionally, the pressure data from the A-1 Observation
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wells improve the Company’s understanding of how gas moves within these
geological formations.39 The potential benefits of these investments may include
more efficient operation of storage facilities and improved understanding of storage
inventory variances and adjustments. The Company intends to continue investing
similarly to better understand and operate its underground storage pools in the
future, as appropriate.
Advanced Metering Infrastructure
70. As noted in its 2024 Phase 1 Rebasing application,40 Enbridge Gas is committed to
Advanced Metering Infrastructure (AMI) and advised that it plans to file a stand-
alone AMI application as soon as practicable that will request approval from the OEB
for funding and to implement an AMI solution. In its 2023-2032 Asset Management
Plan,41 the Company went on to explain that AMI is expected to provide significant
customer benefits including, but not limited to, reducing meter reading and call
centre costs and eliminating estimated bills, while providing customers insight into
their gas usage. The Company advised that an AMI Proof of Concept (PoC) project
is currently underway which will inform the scope of the AMI program and any future
AMI-related application to the OEB. In its Decision and Order, the OEB noted that
the AMI PoC project is a positive step in managing meter reading performance and
directed the Company to provide an update on the project in Phase 3 of the 2024
Rebasing proceeding.42
71. The Company has progressed through several key deliverables and design activities
as part of the development of a strategic business case, it has built strong working
relationships with AMI vendors, and it has developed a deeper understanding of key
AMI technologies. The Company’s AMI PoC went “live” on December 1st, 2023, and
39 Recent stratigraphic test wells include at the Ladysmith Storage Pool (EB-2019-0012/EB-2020-0256),
and at the Crowland Storage Pool (EB-2022-0155). Recent A-1 observation wells include at the Corunna
and Ladysmith Storage Pools (EB-2021-0079) and at the Coveny and Kimball-Colinville Storage Pools
(EB-2021-0248).
40 EB-2022-0200, Exhibit 2, Tab 7, Schedule 2, p. 6.
41 EB-2022-0200, Exhibit 2, Tab 6, Schedule 2, p. 170.
42 EB-2022-0200, OEB Decision and Order, December 21, 2023, p. 135.
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will practically demonstrate and validate the benefits of AMI systems. The objectives
of the PoC currently include:
Showcase AMI capabilities, safety features and qualitative benefits of the
meter technology in both laboratory and real-world settings.
Demonstrate and validate advanced AMI communication use cases including
collecting detailed data sets.
Demonstrate and validate network functionality and system security.
Next steps regarding the PoC are to further evaluate AMI through several Enbridge
Gas stakeholder test cases over the remainder of 2024.
72. AMI is anticipated to positively impact future UFG volumes/costs in multiple ways,
including:
In terms of physical loss and theft of gas, AMI meters with internal
sensors/alarms will detect and enable near real-time remote monitoring of
distribution system performance at the customer premises level. AMI meters
at customer premises fitted with automated tamper alarms will also alert the
Company to instances of theft. When combined with flow and pressure data
up to and including at gate stations, the Company expects to amass more
precise measured Consumption data on an hourly basis which should
translate to reduced variability in UFG volumes.
In terms of measurement quality, AMI can lay the foundation to enable
Enbridge Gas to remotely monitor and manage the meter population,
ensuring that appropriate and properly functioning assets are deployed and
maintained to ensure a high degree of measurement data accuracy. The
improved accuracy and reliability of hourly Consumption data is expected to
contribute to the resolution of backlogs of unbilled and No Bills incidents and
to eliminate billing based on estimated Consumption in the future. An
anticipated consequence of these improvements is a reduction in UFG
volatility.
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Pressure Elevation Factors
73. For communities that fall within more than one elevation zone (with an elevation
difference exceeding 110 m between maximum/minimum elevations), unique
elevation factors (e.g., air pressure, barometric pressure area) may need to be
established in the Company’s billing systems to adjust for the effect of atmospheric
pressure on volumes of natural gas delivered. Absent such elevation-specific
factors, UFG loss/(gain) can result. The Company is currently reviewing pressure
elevation factors for existing customer premises across the system to ensure such
factors are set consistent with Measurement Canada standards and has taken steps
to ensure that all new premises are set up with compliant factors at the time of
account creation. The Company expects that this initiative will result in more
accurate gas consumption and billing data and may result in reduced UFG (overall).
74. The Company is not currently able to accurately estimate the net impact that
erroneous pressure elevation factors had on UFG volumes recorded in recent years
given the need to investigate the circumstances of each instance to understand its
magnitude and duration.
Loss of Containment (Gas Loss Due to Damage Events)
75. An initiative was launched in 2023 to assess and improve emission mitigation
practices and the accuracy of gas loss calculations associated with instances of
facility damage from third parties. By comparing legacy EGD and Union processes,
the Company concluded that it was not consistently calculating and charging third
parties (e.g., construction contractors) for such damage events and any associated
gas loss (Damage Recoveries) across the EGD and Union Rate Zones.
Furthermore, differences existed in how Damage Recoveries were recorded in the
relevant UFG deferral/variance accounts in the EGD and Union Rate Zones. In the
UAFVA for the EGD Rate Zone, Damage Recoveries were removed from the
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UAFVA balance, whereas in the UFGVA for the Union Rate Zones, there was no
adjustment made.
76. Enbridge Gas estimates that annual volumetric gas loss associated with third-party
damage events have exceeded 1,000 103m3 consistently since 2021 as shown in
Table 7. While annual gas loss volume attributed to such events have been declining
over that same period, the Company sought to better understand and mitigate such
losses, to the extent possible.
Table 7
Estimated Natural Gas Loss Due to Third-Party Damages
Line
No.
Year
Gas Losses
(103m3)
1 2021 2,380
2 2022 1,348
3 2023 1,173
77. Accordingly, Enbridge Gas assessed current processes and best practices to
develop a common set of guidelines for field reporting during damage events (i.e.,
damage size, location, nature of facilities damaged, duration of methane release,
system pressures, provide scale photos, etc.) and for charging for the associated
gas loss. As part of its 2024 Phase 1 Rebasing Application, the Company proposed
a standard set of Loss of Containment Cost Recovery Charges based on the
pipeline diameter, operating pressure, duration of loss of containment, and cost of
gas volume lost. Depending upon the specific circumstances surrounding damage
events in the future, third parties may face no charges, flat rate charges or specific
calculations using Rate 320. Currently, Enbridge Gas is working to establish a
standard form and process to gather the information necessary to support these
changes and expects to implement the new guidelines and processes by the end of
2024, including system upgrades, and updated training and education. In addition,
with the implementation in 2024 of the harmonized UFGVVA, adjustments to remove
gas loss recoveries will be consistently made going forward.
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Measurement Integration
78. As previously noted in its 2024 Phase 1 Rebasing evidence and in response to
interrogatories in Enbridge Gas’s 2023 Deferral and Variance Account Clearance
proceeding, the Company continues to align applications and equipment used for
large volume customer measurement to ensure consistency in volume measurement
data validation for all contract large volume customers.43 In 2023, Enbridge Gas
aligned on a solution to migrate from a near-obsolete measurement system that
transmits pulse counts, to a new endpoint connectivity device that transmits serial
measurement data.44 This initiative is planned to be completed by 2025, and will
result in a single measurement system for all large volume contract rate customers.
79. The Company expects that this work could contribute to related initiatives in the
future to deploy remote interval metering solutions to commercial and General
Service customers as it could eliminate the need for manual meter readings of
customer consumption.45
80. At this time, the Company is exploring technological alternatives for commercial and
General Service customers that would enable the installation of endpoint
connectivity devices that are compatible with existing metering assets. Should such
an initiative proceed, other considerations would include preferentially targeting
General Service customers with the highest annual Consumption rates and that are
served by existing systems that are currently or are forecast to be at capacity. Given
the magnitude of natural gas volumes consumed by General Service customers, the
Company expects that replacement of manual meter reading with an automated and
remote process for those customers could significantly reduce incidence of billing
based on estimated Consumption and related UFG volumes.
43 EB-2022-0200, Exhibit I.1.9-CCC-25, Attachment 1, p. 1; EB-2023-0092, Exhibit I.STAFF.6, p. 2.
44 Pulse counts refers to electrical pulses from which the volume of customer consumption is derived (i.e.,
counting each instance that a corrected unit of measure has flowed). Serial measurement data refers to
actual measured customer consumption volume data (including corrected or uncorrected measurement,
temperature, pressure, correction factors, flow time, etc.) received directly from EVCs.
45 Large multi-residential, manufacturing, office and other commercial General Service customers
numbered approximately 10,000 and consumed more than 3 million m3 as of 2021.
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Large Volume Customer Measurement for Power Generation
81. Given their inherent physical limitations, aligning customer measurement facilities
accurately with changing customer consumption patterns over time is a common
challenge for utilities across the natural gas industry. For example, some of Enbridge
Gas’s large volume natural gas-fired power generator customers’ operations have
changed over time. Many natural gas-fired power generators that originally operated
at high load factors as a base load power generator (constantly consuming large
volumes of gas) now operate at much lower load factors as peaking plants
(consuming large volumes for short, infrequent periods) and often remain idle until
called upon by the IESO to generate electricity. Such facilities can have large
properties, often including administrative offices, maintenance buildings, and turbine
buildings which also use natural gas for building space and water heating throughout
the year, even when not generating electricity. While the measurement facilities
originally designed and installed by Enbridge Gas for these customers continue to
measure accurately under their original high load factor conditions, they do not
measure Consumption accurately under low-flow conditions (i.e., when turbines are
not running).
82. Enbridge Gas has completed a high-level assessment of the capabilities of the
existing measurement facilities installed for such customers and has determined that
several were not designed to accurately measure natural gas volumes under low-
flow conditions. In other words, the measurement facilities currently on site may be
oversized relative to some current operating conditions. Work on this initiative is
preliminary in nature and a project team is being formed to assess: (i) customer site-
specific measurement station capabilities, layouts, and physical constraints; (ii) the
estimated magnitude of unmeasured volumes; and (iii) engineering solutions (e.g.,
installation of low-flow measurement) for these facilities.
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Page 246
83. The Company intends to work closely with these customers to determine what
ancillary natural gas appliances exist on-site as a first step towards estimating
unmeasured volumes. Where applicable, the Company intends to apply lessons
learned through this investigation to other large volume customer sites to ensure that
measured and billed Consumption volumes are as accurate as possible. The
Company has also developed a harmonized Measurement Design Standard to avoid
instances of inaccurate measurement under low-flow conditions going forward.
Similarly, as the issue of managing measurement limitations across dynamic
customer groups over time is common across the North American natural gas
industry, Enbridge Gas will monitor such issues identified by other utilities as well as
any solutions implemented in case there is opportunity to apply lessons learned or
best practices to the Company’s engineering design standards or internal
processes/systems.
Operational Emission Reductions
84. As discussed in its 2024 Phase 1 Rebasing Application,46 to support achievement of
federal and provincial GHG reduction targets Enbridge Gas has identified a number
of emission reduction opportunities (some of which have already been included in
the Company’s Asset Management Plan).47 Certain of these opportunities also have
the potential to impact UFG volumes. At this time, the Company has not assessed
the respective impacts of each opportunity on UFG volumes. However, going
forward the Company will consider such impacts, where quantifiable, when
prioritizing such investments.
Section 2: Impact of No Bill Customer Volumes on UFG
85. As discussed in Section 1.3, the Consumption volumes used to calculate UFG
include both billed Consumption and unbilled Consumption volumes:
46 EB-2022-0200, Exhibit 1, Tab 10, Schedule 8, pp. 1-7.
47 66,100 tCO2e per year of scope 1 and 2 GHG emissions are expected to be reduced by initiatives
already being undertaken as part of the Company’s Asset Management Plan or operational maintenance
programs. Up to an additional 351,000 tCO2e per year of emissions reductions are possible subject to
economic assessment and prioritization.
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Billed Consumption Volumes – customer Consumption calculated based on a
combination of actual meter reads and estimated meter reads interfaced from
the Company’s billing system into its financial accounting system.
Unbilled Consumption Volumes – an estimate of gas delivered but not yet
billed, calculated at the rate class level at the end of every monthly
accounting period and recorded within the financial accounting system based
on factors such as number of customers per billing cycle, number of days for
each cycle which have not been billed, average use per HDD, actual HDDs,
and demand coefficients.
86. No Bills are categorized as Unbilled Consumption Volumes that occur as a result of
extenuating circumstances such as unexpected Consumption or charges being
generated on customer bills that exceed established volumetric and monetary
thresholds and trigger manual intervention before any bill can be issued to a
customer(s).
87. As detailed in response to undertakings in its 2024 Rebasing proceeding,48 the
Company has several mechanisms in place to validate meter reading and billing
accuracy that can trigger manual review and/or intervention before any bill can be
issued to customers, including:
Validation that meter readings are within accepted tolerances and manual
review of exceptions relative to factors such as historical readings, known
natural gas appliances in service, and geographic weather zone.
Validation that commodity and supply-related costs are being appropriately
applied according to the customer’s specific rate class. For residential
customers, a monetary threshold of $800 for such costs ensures that any bills
exceeding this amount are manually reviewed before being issued.
48 EB-2022-0200, Exhibit JT3.35.
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Validation that the total dollar value of bills is within established thresholds.
For residential customers, a monetary threshold of $2,100 ensures that any
bills exceeding this amount are manually reviewed before being issued.
88. In No Bills scenarios, while no bill is generated for the affected customer(s) in line
with its particular monthly billing cycle, the Company’s financial practice is to record
an estimate of volumes delivered but not yet billed in the financial accounting system
for the relevant monthly accounting period. Typically, this estimate is reversed in a
subsequent accounting period and replaced with actual billed Consumption
(contingent upon its availability) at the applicable QRAM rate, and any difference is
corrected via volumetric adjustment in the financial accounting system. If the
Company’s estimate of No Bills recorded in the financial accounting system for any
monthly accounting period is understated relative to actual billed Consumption, it
creates a UFG loss in the period that the estimate was recorded and creates a UFG
gain in the subsequent period when the estimate is reversed and replaced with
actual billed Consumption. The inverse is true in instances when No Bills estimates
are overstated.
89. As noted in Section 1.3, UFG is calculated as the monthly difference between
Sendout and Consumption volumes and is composed of a combination of actual
physical gas losses/gains and temporary variances resulting from estimation in
billing and accounting processes, including No Bills. Therefore, while No Bills do not
impact actual UFG volumes in the long-term, they can contribute to intra-period UFG
volume volatility via variances in the short-term. Further, intra-period volatility that is
not resolved (estimates reversed and replaced with actual Consumption) before
annual fiscal accounting records are closed can result in lasting timing variances to
UFG levels spanning fiscal periods (i.e., under or overstated No Bills estimate and
commensurate UFG loss or gain).
90. Table 8 provides the historical impact of No Bills true-ups for 2022 and 2023 for the
Union and EGD rate zones.
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Table 8
Historical Impact of No Bills True-ups (103m3)
Line
No. Particulars (103m3) 2022 2023
1 Union Rate Zones
27,405
(25,031)
2 EGD Rate Zone
36,563
(27,373)
3
Impact to UFG Volumes:
Increase/(Decrease)1
27,405
(25,031)
Notes:
(1) UFG Impacts of No Bills in 2022 and 2023 are limited to the Union Rate
Zones impacts as the EGD Rate Zone volumes displayed in row 2 were
trued-up and did not contribute to reported UFG volumes in each year.
91. As discussed in Section 1.3, for the EGD Rate Zone Enbridge Gas has the ability to
eliminate timing variances that span two fiscal years related to unbilled estimated
Consumption (including No Bills) via an accounting adjustment in the subsequent
fiscal year to record differences between estimated and actual UFG. However, no
such provision to record any adjustments related to unbilled estimated Consumption
across fiscal years has historically existed for the Union Rate Zones. Said differently,
to the extent that a variance existed between estimated Consumption and actual
Consumption for the Union Rate Zones, any adjustment(s) made after December
have historically been recorded in the subsequent fiscal year. As a result, unbilled
estimate-related UFG volumes for the Union Rate Zones increased UFG volumes in
2022 and subsequently suppressed UFG volumes in 2023.
92. Effective January 2024, the accounting treatment for all rate zones will be
harmonized, including the use of a single UFGVVA that includes a provision
enabling the Company to uniformly adjust for differences in estimated UFG and
actual UFG to avoid timing variances across fiscal years. As a result, the Company
expects that intra-year volatility experienced in the Union Rate Zones from No Bills
true-ups will be markedly reduced.
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93. Between December 2022 and March 2023, multiple system changes were
implemented to reduce the number of No Bills exceptions created by bills that were
outside of pre-determined thresholds. These changes targeted 6 common scenarios
with clear paths to resolution. Programs were developed to automate these
scenarios and remove the need for agent intervention in order to release the bill to
the customer. In addition, a comprehensive review of work prioritization was
completed resulting in the implementation of process improvements that reduced the
time to correct No Bills scenarios.
94. Going forward, Enbridge Gas intends to continue the initiatives discussed in Section
1.3, including its consecutive estimate campaign, inbound calls campaign, customer
outreach campaign, and meter reading processes campaign, all of which have the
potential to significantly reduce the impact of No Bills in the future. Similarly, the
Company is also investigating a variety of system enhancements tied to the No Bills
estimation process, including refinements to the determination of the number of
missing billing periods, determining the relevant HDDs for each respective missing
billing period rather using a common HDD for all periods, and differentiation of
QRAM pricing used when No Bills periods span multiple quarters.
Section 3: Impact of Transmission & Other High-Pressure System Linepack on UFG
95. The term “Linepack” generally refers to the quantity (volume) of natural gas or
inventory in a pipeline system at a given time. Pipeline systems are, in a way,
storage facilities and the Linepack contained in these systems relates directly to the
size of the facility, or its physical volume, which is based on its diameter and length.
The physical volume of a pipeline can be calculated using the following equation:49
49 Equation 3.30, Gas Pipeline Hydraulics by E. Shashi Menon (2005).
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Vp ൌ π
4 DଶL
Where:
Vp = physical volume (ft3)
D = pipe inside diameter (ft)
L = pipe segment length (ft)
96. Since natural gas is compressible, the amount of gas a pipeline contains can vary
depending upon the physical conditions it is stored under, including pressure, gas
temperature, and the chemical properties of the gas stored. Generally, Linepack is
positively correlated with increases in pipeline diameter, pipeline length, pipeline
pressure, and colder gas temperatures. Linepack volume can be calculated using
the following equation:50
Vb ൌ 0.7854 ൬Tb
Pb൰൬ Pavg
ZavgTavg൰ DଶL
Where:
Vb = Linepack in pipe segment (standard ft3)
D = pipe inside diameter (ft)
L = pipe segment length (ft)
Tb = base temperature (ºR)
Pb = base pressure (psig)
Pavg = average gas pressure in pipeline segment (psig)
Tavg = average gas temperature in pipe segment (ºR)
Zavg = average gas compressibility factor at Tavg and Pavg
97. Except for certain maintenance-related purposes, pipelines are normally never
completely emptied of natural gas volumes.
98. Typically, natural gas customers consume gas in a diurnal (24 hour) cycle; the
50 Equation 3.33, Gas Pipeline Hydraulics by E. Shashi Menon (2005).
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lowest demands occur overnight while most customers are sleeping/inactive, and
the highest (peak) demands occur during the morning and afternoon/evening while
most customers are starting or ending their day. Operating pressures (including
Linepack) on pipeline systems fluctuate in response. The highest pressures occur
overnight, and the lowest pressures occur during the morning and
afternoon/evening.
99. While the definition of Linepack set out above applies to all forms of Linepack, for
the purposes of modeling and managing its pipeline systems Enbridge Gas
commonly refers to two distinct forms of Linepack: (i) “Minimum Linepack”, and (ii)
“Operational Linepack”.
100. Enbridge Gas generally defines Minimum Linepack as the volume of natural gas
required to fill a pipeline to the minimum level required to make the system
operational.
101. Enbridge Gas generally defines Operational Linepack as the volume of natural gas
required to operate a particular pipeline system. Operational Linepack ranges
between minimum system pressure and MOP of a particular pipeline system.
Operational Linepack is required to operate the pipeline system and provide
reliable service to customers, because higher pressures (above Minimum
Linepack) are needed to provide the “push” required to move gas through the
pipeline system from high to low pressure.
102. Enbridge Gas draws further pipeline system-specific distinctions between Minimum
Linepack and Operational Linepack for the purposes of modelling and managing
Linepack across its high-pressure storage and transmission pipeline systems,51
and its high-pressure distribution pipeline systems. Accordingly, the sections of
evidence that follow explain those system-specific distinctions and describe the
51 For the purposes of this evidence, Enbridge Gas classifies “transmission pipeline systems” as
specifically being the Dawn to Parkway transmission system, the Panhandle transmission system, the
Sarnia transmission system, and the Albion Line.
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Company’s work to assess the effects of all forms of Linepack upon UFG.
103. In all instances of Linepack (i.e., Minimum and Operational), the Company has
assessed the related factors considered in calculating Sendout (see description set
out in Section 1.3) and has determined that changes in Linepack did not
significantly impact UFG levels in 2022 or 2023.
Section 3.1 – Minimum Linepack
104. Minimum Linepack for transmission pipelines and high-pressure storage pipelines
is calculated annually using system-specific models that consider the Linepack
factors discussed above as well as reduced supply pressure, either to lowest
anticipated level (minimum pressure of gas supply available) or to the level
required to meet minimum contractual obligations.
105. Minimum Linepack for distribution pipelines is also calculated annually using
system-specific models that consider the Linepack factors discussed above,
balanced on a peak hour design condition according to temperature zone,52 that
assume that interruptions are called, and that producer injections are restricted. A
further distinction of Minimum Linepack modelling for distribution pipelines is that
the pressures near system source stations or takeoffs are highest, while the
system extent pressures (or system constraints) are near or at their design
conditions. Accordingly, Enbridge Gas views distribution pipeline Minimum
Linepack as the volume of gas in a particular distribution pipeline system that is not
forecasted to be consumed and billed on a design day. Accordingly, distribution
system Minimum Linepack varies annually depending on forecasted demand
changes (general service or contract rate volumes), forecasted new in-service
pipelines, and forecasted abandonments.
52 Using peak morning demands and resulting pressures for unsteady state models.
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106. In Enbridge Gas’s experience, Minimum Linepack typically does not change
drastically from year to year because of updates made to the Linepack factors
discussed above. Minimum Linepack is most often influenced by circumstances
wherein pipeline facilities are added/removed to/from a modelled pipeline system.
In 2024, Enbridge Gas completed an assessment of recent adjustments to
Minimum Linepack for all pipeline systems and concluded that all such
adjustments were adequately accounted for and directly attributable to specific and
intended changes to the Company’s facilities and/or operations and were not
significant contributors to UFG volumes in 2022 or 2023. Table 9 provides
historical Minimum Linepack data from 2021 to 2023:
Table 9
Historic Minimum Linepack 103m3
107. A net increase in total calculated Minimum Linepack of 251 103m3 observed from
2021 to 2022 is attributable to various annual updates to inputs and assumptions
across many storage and distribution system Linepack models. A net reduction in
total calculated Minimum Linepack of 670 103m3 observed from 2022 to 2023 is
attributable to various annual updates to inputs and assumptions across many
Line
No.
2021
2022
2023
1 Union Rate Zones
2 Transmission 28,273 28,250 28,382
3 Storage 1,329 1,507 1,494
4 Distribution 7,346 7,240 7,309
5 Total Union Rate Zones 36,947 36,997 37,185
6 EGD Rate Zones
7 Transmission 926 926 926
8 Storage 1,168 1,125 1,804
9 Distribution 8,072 8,317 6,780
10 Total EGD Rate Zone 10,166 10,367 9,509
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distribution system Linepack models, and increases to transmission minimum
Linepack associated with gas property adjustments.
108. In all instances (transmission, storage, and distribution pipelines), Enbridge Gas
treats Minimum Linepack as a fixed asset which cannot be sold or otherwise used
and as a non-depreciable “property, plant, and equipment” valued at historical gas
costs. In this regard, minimum Linepack in a pipeline is comparable in its purpose
and accounting treatment to “cushion gas” volumes that are maintained within
underground storage reservoirs.
109. If there is a change in Minimum Linepack, there is a corresponding change in the
determination of Sendout. As described in Section 1.3, Sendout is the net volume
of natural gas delivered into the Enbridge Gas distribution system to serve in-
franchise customer demands after accounting for receipts and deliveries across
Enbridge Gas’ integrated storage, transmission, and distribution systems. Since
there is no corresponding billed consumption associated with the change in
Sendout resulting from the change to Minimum Linepack, it results in amounts
recorded as UFG as part of the Sendout side of the equation discussed in Section
1.3. As such, an adjustment is recorded to remove the cost associated with the
change in Minimum Linepack from UFG and the offsetting amount is recorded as a
fixed asset.
Section 3.2 – Operational Linepack
Transmission and Storage Pipeline Systems
110. For Enbridge Gas’s transmission and storage pipelines, Operational Linepack
ranges between minimum and maximum operating pressures above the Minimum
Linepack up to the maximum Linepack based on the MOP of a particular pipeline
system. Transmission and storage system Operational Linepack varies,53 as
system pressures change to serve customer demands.
53 Operational Linepack will fluctuate daily, weekly, monthly, seasonally, and annually.
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111. As described in the Company’s 2024 Phase 1 Rebasing evidence,54 certain
Enbridge Gas transmission pipeline systems are designed using transient
hydraulic modelling techniques to partially serve design day demand via
Operational Linepack:
The Dawn Parkway System and Panhandle System are sized to serve the
design day demand with the hourly demand changes served from the system’s
linepack. Linepack is the amount of natural gas storage within a pipeline and
occurs because gas is compressible and becomes a usable asset in facilities
design in large diameter, high pressure pipelines. When the hourly demand is
greater than the design day demand the system pressure is dropping or known
as “drafting” or losing linepack and when the hourly demand is less than the
average daily demand the system pressure is increasing or known as ‘packing”
or gaining linepack. The ability to use linepack in transmission systems
reduces the need for facilities as the facilities can be sized for the daily demand
rather than the design hour demand.
112. The daily use of Operational Linepack for these purposes does not impact UFG
volumes as any resulting variance in Linepack, either draft or pack, is typically
recovered and balanced by the end of the gas day. Each segment of the Dawn
Parkway Transmission System has pressure telemetry at mainline valve sites that
provide sufficient data for the Company to calculate the Operational Linepack for
the system on a daily basis. On a monthly basis, an entry is recorded to reflect the
net increase or decrease to Operational Linepack as a movement between working
inventory and Linepack inventory. Accordingly, the variation in Operational
Linepack for each month for this system is accounted for in the determination of
Sendout, discussed in Section 1.3, ensuring that it does not cause any variation in
monthly or annual UFG calculations.55
113. Enbridge Gas assessed Operational Linepack changes observed on the Dawn
Parkway Transmission system from 2022 and 2023 to gauge the significance of
such changes relative to calculated UFG volumes. The largest month over month
54 EB-2022-0200, Exhibit 2, Tab 7, Schedule 1, p. 16.
55 Enbridge Gas does not have comparable pressure telemetry on its other transmission and high-
pressure pipeline systems, and thus does not have the data needed to calculate and track system
Operational Linepack similarly. However, the Company expects the proportional magnitude of impacts
due to Operational Linepack adjustments to be similar in all instances to those discussed in Table 11.
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Operational Linepack changes observed, set out in Table 10, were found to be
negligible. As shown in Table 10, the Linepack adjustments for each of August
2022 and September 2022, and October 2023 and November 2023 represented
0.03-0.1% of the respective month’s system activity.
Table 10
Dawn-Parkway Operational Linepack Adjustments
Line
No. Particulars (103m3) Aug 2022 Sep 2022 Oct 2023 Nov 2023
(a) (b) (a) (b)
1 Absolute Activity 4,075,901 3,321,413 2,529,696 4,721,557
2 Total Receipts 2,386,408 1,977,352 1,669,918 2,946,788
3 Total Deliveries 1,689,492 1,344,061 859,779 1,774,769
4 Dawn Parkway System Linepack Receipts 2,093 - 2,288 -
5 Dawn Parkway system Linepack Deliveries - 3,427 - 1,404
6 Dawn Parkway System Linepack Adjustment
(% of absolute activity) 0.05% 0.10% 0.09% 0.03%
114. While Operational Linepack also varies by season for transmission pipeline
systems, the adjustments discussed below are offsetting:
(i) Transmission pipeline operating pressures (including Operational Linepack)
are increased in the fall, by way of increased system set pressures or by
turning on compression, in advance of winter season conditions to serve
anticipated increased customer demands. See Figure 4 for an illustrative
example of this relationship.
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Figure 4: Winter Transmission Pipeline Linepack
(ii) Transmission pipeline operating pressures (including Operational Linepack)
are reduced in the spring, by way of decreased system set pressures or by
turning off compression, in response to lower needs of summer season
conditions to serve anticipated reduced customer demands. See Figure 5
for an illustrative example of this relationship.
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Figure 5: Summer Transmission Pipeline System Linepack
Distribution Pipeline Systems
115. For the Company’s high-pressure distribution pipelines, Operational Linepack also
varies between minimum and maximum operating pressures. Distribution pipeline
system station pressures are typically held constant year-round and demands
reduce over the length of each segment. As a result, the proportion of natural gas
volumes deemed to be Operational Linepack on the system fluctuates throughout
the year. Generally, distribution pipeline Operational Linepack increases in the
summer, and spring/fall (shoulder months) seasons since customer demands are
reduced relative to winter.56 See Figure 6 for an illustrative example of this
relationship.
56 The caveat to this is when systems are undergoing maintenance, pipelines are isolated, during
emergency work, or when station set pressures are modified or a station is taken out of service.
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Figure 6: Linepack for Other High Pressure Pipeline Systems
116. Certain distribution pipeline systems that are directly connected and supplied by
transmission pipelines that provide supply at variable pressures may at times
experience reduced inlet/system station pressures, even during summer season
and shoulder months. In such circumstances, similar to the discussion above
regarding transmission pipeline system Linepack, any seasonal variability in
operating pressures (including Operational Linepack) is offsetting (Operational
Linepack increases made in advance of winter are reduced the following spring).
Section 4: The Fugitive Emissions Measurement Plan Project
117. In the Partial Settlement Proposal for Enbridge Gas’s 2024 Phase 1 Rebasing
proceeding,57 the Company agreed to:
…investigate and determine an appropriate way to accurately measure fugitive
emissions, including consideration of top-down measurements (i.e., by aircraft,
satellite, and/or towers), with the goals of: (a) confirming the volume of fugitive
emissions, (b) determining if recent UFG increases could be due to fugitive
emissions, and (c) attempting to locate specific fugitive sources that can be
mitigated. This would include all kinds of assets (transmission, rural & urban
distribution, and storage). Enbridge Gas will file a robust investigation plan for
57 EB-2022-0200 Partial Settlement Proposal, Exhibit O1, Tab 1, Schedule 1, July 12, 2023, p. 37.
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consideration and determination in the 2023 deferral and variance account
proceeding, which filing shall include justification of the planned approach
including, without limitation, whether it will include aerial (i.e., top-down)
investigation.
The Company’s commitments to determining if recent UFG increases could be
due to fugitive emissions was reiterated in the Settlement Proposal for the 2022
Earnings Sharing and Deferral and Variance Account Clearances proceeding.58
118. Enbridge Gas determined that in order to satisfy its commitments made above, the
first step to meeting goals (a) through (c) would be to expand the Company’s
actual measurement of fugitive emissions to more accurately quantify volumes.59
Methane measurements will allow Enbridge Gas to more accurately determine the
contribution of fugitive emissions to UFG moving forward and to identify material
contributors to the fugitive emissions inventory. This will support the
implementation of targeted reduction strategies that are both efficient and effective.
Accordingly, Enbridge Gas initiated the Fugitive Emissions Measurement Plan
(FEMP) Project in August 2023 and commissioned a third-party expert consultant,
Highwood Emissions Management Inc. (Highwood), to support its work to
investigate and analyze fugitive emission sources and support the development of
an investigation plan. Highwood’s final report is set out at (Attachment 1 to this
exhibit) (the “Highwood Report”).
119. Highwood’s investigation included:
a) Evaluating and confirming the Company’s 2022 fugitive emissions
inventory –
Highwood’s analysis (Highwood Report, Section 7.2) showed that
84% of Enbridge Gas’s fugitive emissions arose from Distribution
Operations (DO) with the remaining 16% from Storage and
Transmission Operations (STO).
Highwood’s analysis (Highwood Report, Section 7.5) showed that DO
fugitive emissions were calculated using default published emission
58 EB-2023-0092 Settlement Proposal Exhibit N1, Tab 1, Schedule 1, November 28, 2023, pp. 19-20.
59 Fugitive emissions were understood to mean the unintended release of natural gas due to leaks or
third-party damages. They do not include emissions from venting, combustion, or flaring.
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factors (EFs), while the majority (>70%) of STO fugitive emissions
were calculated through direct measurement of emissions using
Optical Gas Imaging, followed by flow rate measurement using Hi-
Flow samplers.
Highwood referenced a 2021 uncertainty analysis (Highwood Report,
Section 7.6) that estimated the uncertainty in Enbridge Gas’s STO
fugitive emissions to be <10%, while the uncertainty in DO emissions
was estimated to be >115%. This is likely due to the fact that DO
emissions are calculated using default published EFs while the
majority of STO emissions are measured directly.
b) Reviewing fugitive emissions quantification methodologies and
measurement technologies –
Highwood’s review (Highwood Report, Section 5.3) identified potential
methodologies to more accurately calculate fugitive emissions,
including developing company-specific EFs using representative
sample measurements and directly measuring system-wide
emissions. Highwood’s review focused on the DO segment, due to its
larger contribution to overall fugitive emissions and the higher
uncertainties associated with the current emission calculation
methods.
Highwood conducted a review of potential emissions measurement
technologies (Highwood Report, Section 6.2) and identified the
suitability of hand-held and mobile (vehicle) measurement solutions.
As previously mentioned, Highwood’s review focused on the DO
segment, due to its larger contribution to overall fugitive emissions
and higher uncertainty.
Highwood advised against adopting aerial and satellite technologies
(Highwood Report, Section 9.4) since they lack the sensitivity to
detect smaller leak sizes characteristic of downstream operations and
are unlikely to enhance the accuracy of fugitive emissions from DO
assets.
c) Recommendations –
Highwood recommended the following to improve the accuracy of the
fugitive emissions inventory:
The development of company-specific EFs for DO, prioritizing sources
with high materiality and high levels of uncertainty.
Piloting a Mobile Ground Detection (vehicle) measurement strategy
for DO, and using the outcomes and lessons learned from the pilot to
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direct future measurement efforts to improve the accuracy of the
emissions inventory. It was suggested to evaluate the piloted mobile
technology with respect to its ability to accurately detect and quantify
leaks.
Working towards the development of a measurement-informed
inventory, using data obtained through the first two recommendations.
Monitoring advances in aerial and satellite performance and
evaluating emerging technology capabilities for suitability for
deployment on distribution systems.
High-level cost estimates for system-wide implementation of different
measurement scenarios were provided by Highwood (Highwood Report, Section
8.4)60
Table 11
Highwood High-level Cost Estimates ($millions)
Line
No. Method Upfront
Costa,b Survey Costa Subscription
Costsa Annual Totala
1 Annual Handheld $ 1.7 $ 28.0 - $ 29.7
2 Annual Vehicle $ 22.7 $ 4.7 $ 5.7 $ 33.1
3 Annual Aerial - $ 12.0 - $ 12.0
4 Annual Satellite - $ 10.0 - $ 10.0
a. Costs are in USD based on available information from US vendors and other sources.
b. Upfront costs are annualized over five years. Total upfront costs for the Annual Handheld is $8.5 million
and the total upfront costs for the Annual Vehicle is $113.5 million.
Section 4.1 – Investigation Plan
120. Enbridge Gas’ 2022 leak volumes were 18,118 103m3 (including leak volumes
related to both DO and STO), representing 4% of the Company’s 2022 UAF/UFG
volumes (EGD and Union Rate Zones combined). As previously discussed, these
volumes were primarily due to leaks from DO which were calculated using default
published EFs, with an estimated uncertainty of >115%. Emission factors can
underestimate or overestimate emissions. However, measurement-informed
inventories are generally more accurate than emission factor methods as they
utilize measurement in place of generic assumptions.
60 These high-level cost estimates were not based on vendor quotes for Enbridge Gas’ system and will
need to be validated. Highwood’s cost estimate did not include internal resourcing to repair leaks.
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121. Improving the accuracy of fugitive emissions reporting in a transparent and
credible manner will require the implementation of a combination of technological,
procedural, and operational enhancements. Based on Highwood’s findings and
recommendations, Enbridge Gas will prioritize the measurement of DO fugitive
emissions, due to their higher contribution to overall emissions and since the
majority of STO fugitive emissions are already being measured and quantified
three times per year. Given the magnitude of the costs associated with the
Highwood system wide implementation of measurement technologies and the fact
that these technologies are rapidly evolving, Enbridge Gas is proposing to begin
development of company-specific emission factors on a subset of assets and to
pilot a mobile ground technology on a portion of the distribution system, as part of
the Investigation Plan outlined below. The results of this mobile ground pilot and
preliminary company-specific emission factor work, proposed to begin in 2025, will
help inform next steps in the development of a broader fugitive emissions
measurement program to support the development of a measurement-informed
inventory.
122. The following outlines the key details of the Enbridge Gas Investigation Plan:
Begin developing a measurement informed inventory, prioritizing the most
material emission sources with the highest uncertainties in the Distribution
segment.
As part of this process, company-specific emission factors will be developed
on a subset of assets, which will be an iterative and evolving process. Repeat
programs may demonstrate consistency or highlight where further
investigation is required. The outcomes of this work will be used to inform
next steps in developing company-specific DO fugitive emission factors.
This will include:
developing a robust, statistically valid sampling strategy,
implementing a measurement plan, and
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Exhibit D
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data analysis and statistical modeling to develop company-specific
emission factors and determine confidence intervals.
Piloting a mobile ground (vehicle) technology for detecting and measuring DO
fugitive emissions on a limited portion of the DO system. Enbridge Gas plans
to evaluate the selected technology’s suitability for both detecting and
quantifying leak flow rates which will require comparison against baseline
walking surveys and flow rate measurements. The outcomes and lessons
learned from the pilot will be used to direct future measurement efforts.
Given the diversity of GDS assets and the rapidly evolving technologies, it is
expected that a variety of different measurement technologies may eventually
need to be evaluated and adopted.
A pilot will provide real-world, in-field evaluation of the recommended
technology. This will include:
designing a pilot program (goals, location, duration),
deploying a mobile ground (vehicle) measurement technology,
validating mobile technology performance against known methods,
conducting the required follow-up investigations by foot to confirm
and locate leaking components, and
managing and repairing leaks found during pilot program.
Begin configuration and assessment of IT systems. This will include:
configuration of Enbridge Gas’s existing emissions management
database to integrate company-specific data obtained through the
piloted measurement plans, and
Assess implications of potential system-wide integration on current IT
systems
Continue monitoring developments in aerial and satellite technologies to keep
up with rapidly evolving industry and academic research. This will include:
attending training and conferences to keep up with emerging
technologies and advancements in methane measurement research,
and
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evaluation of new technologies as they become available.
Section 4.2 – Administration and Pilot Costs
123. As discussed above, based on Highwood’s recommendations Enbridge Gas is
seeking to pilot a mobile ground emissions measurement technology on a limited
portion of the DO system and to initiate the development of company-specific
emission factors. The anticipated incremental administration and pilot program
costs are detailed below. It is anticipated that if the measurement pilot program is
expanded for wider coverage in the future, further incremental costs will be
incurred.
Table 12
2025 Forecast FEMADA Administration and Pilot Costs ($millions)
Line
No.
Cost Element
Total 2025 Forecasted Costs
1 Technology Pilot 1.7
2 IT System 0.2
3 Staffing Resources 0.4
4 Consulting Support 0.2
5 Other Miscellaneous Costs 0.1
6 Total 2.6
Technology Pilot
124. Based on Highwood’s recommendations, in order to accurately and credibly
measure fugitive emissions and meet the goal of confirming the value of fugitive
emissions, Enbridge Gas is seeking to pilot a mobile ground (vehicle) emissions
measurement technology and initiate the development of company-specific
emission factors. Enbridge Gas anticipates the incremental costs associated with
the pilot program to be $1.7 million. The mobile ground pilot program will require
designing study parameters, deploying a mobile technology, validating and
comparing performance of the technology against known methods, and conducting
follow-up investigations by foot to locate and confirm leaking components.
Incremental management and repair of leaks located during this pilot are not
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Exhibit D
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included in this cost estimate as they would be covered by the Company’s existing
integrity programs. The development of company-specific emission factors will
require creating a statistically valid sampling strategy, implementing a
measurement campaign, and performing data analysis and statistical modeling to
arrive at emission factors with confidence intervals. Enbridge Gas intends to use
learnings from these pilots to inform the next steps in the development of a fugitive
emissions measurement program.
IT System
125. Enbridge Gas has determined that additional IT system functionality will be
required to support the integration of measurement into existing emissions
management and other IT databases. Incremental funding will be required to
reconfigure the emissions management database to utilize company-specific data
obtained through pilot studies. Enbridge Gas anticipates the incremental costs
associated with updating and reconfiguring IT systems for the pilot program to be
$0.2 million.
Staffing Resources
126. The Carbon Strategy team currently comprises five full time equivalents (FTEs).
This level of staffing reflects the current level of work Enbridge Gas has
experienced to-date. With the implementation of a measurement program,
Enbridge Gas expects to require additional incremental staffing resources to
support the increased data management and analysis requirements, to oversee
the deployment of new technology measurement campaigns on Enbridge Gas’
systems, and to offer increased operational support. Enbridge Gas anticipates
incremental staffing costs to be $0.4 million. It is anticipated that if the
measurement pilot program is expanded for wider coverage in the future, further
incremental operational support will be required.
127. Enbridge Gas anticipates that it will incur $0.2 million in external consulting costs
for work supporting the development of company-specific emission factors and a
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Exhibit D
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measurement pilot program, and related analyses. These expenditures are
required to ensure that Enbridge Gas is well-informed of best practices and
procedures for developing robust and credible measurement procedures. Enbridge
Gas may incur additional consulting costs associated with other measurement
pilots, depending on the outcomes and learnings from these early studies, and
should new emerging technologies become viable for testing on Enbridge Gas’
systems.
Other Miscellaneous Costs
128. Enbridge Gas expects to incur approximately $0.1 million in miscellaneous costs
for training, conferences, and memberships associated with methane
measurement technologies and methodologies. Methane measurement
technologies for midstream and downstream segments of the value chain are still
very new and are rapidly evolving in their sensitivity and capabilities. Based on
Highwood’s recommendations (Highwood Report, Section 9.1) to monitor
advances in aerial and satellite performance, Enbridge Gas expects that
incremental funding will be required to keep up with rapidly emerging new
technologies, and to evaluate the suitability of new technologies for the
improvement of Enbridge Gas’s reported fugitive emissions accuracy.
Section 4.3 – New Deferral Account Request
129. To support implementation of the Fugitive Emissions Investigation Plan, Enbridge
Gas is seeking OEB approval to establish a Fugitive Emissions Measurement
Administration Deferral Account (FEMADA) to record the incremental
administration costs, inclusive of Pilot costs, incurred to implement the plan. The
account is proposed to be effective commencing January 1, 2025. Enbridge Gas
will incur costs related to the technology pilot, configuration of IT systems,
incremental staffing, consulting support and other miscellaneous costs, including
training, conferences, and memberships associated with methane measurement
technologies and methodologies. Assuming Enbridge Gas receives approval to
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Exhibit D
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establish a deferral account for these purposes, the Company will record actual
costs in the FEMADA annually until such time that these costs are incorporated
into rates. Enbridge Gas is providing forecasted 2025 FEMADA costs for
informational purposes only and will seek recovery of its actual 2025 administration
and pilot costs in a future proceeding.
130. The Filing Requirements for Natural Gas Rate Applications (Filing Requirements)
require a new D&VA request be accompanied by evidence on how the following
eligibility criteria will be met:61
Causation – the forecasted expense must be clearly outside the base upon
which rates were derived;
Materiality – the forecasted amounts must exceed the OEB-defined
materiality threshold and have a significant influence on the operation of
the distributor, otherwise they must be expensed in the normal course and
addressed through organizational productivity improvements; 62 and,
Prudence – the nature of the costs and forecasted quantum must be
reasonably incurred although the final determination of prudence will be
made at the time of disposition. In terms of the quantum, this means that
the applicant must provide evidence demonstrating as to why the option
selected represents a cost-effective option (not necessarily least initial
cost) for ratepayers
131. Enbridge Gas has assessed the causation, materiality, and prudence of the
FEMADA Deferral Account:
a) Causation: All costs that Enbridge Gas intends to record in the proposed
FEMADA are outside of the base upon which rates are derived.
b) Materiality: Enbridge Gas’s forecasted spend exceeds the $1 million
materiality threshold for the establishment of a new account. As detailed in
Table 12, the Company is forecasting to spend approximately $2.6 million in
FEMADA administration and pilot costs in 2025.
c) Prudence: As noted above, the costs to be incurred are required to support the
Fugitive Emissions Investigation Plan which was developed as agreed to in the
OEB-approved Phase 1 Settlement Proposal. The Fugitive Emissions
Investigation Plan will allow the Company to develop a more thorough
understanding of how to more accurately identify, measure, and potentially
61 OEB Filing Requirements for Natural Gas Rate Applications, February 16, 2017, p. 38.
62 The materiality threshold is set at $1 million for a utility with a revenue requirement of more than $200
million, as defined in the OEB’s Filing Requirements for Natural Gas Rate Applications, February 16,
2017, p.38.
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address/reduce fugitive emissions. Details of the respective cost elements are
set out in Section 4.2.
132. The proposed Accounting Order for the new deferral account is provided at
Attachment 2 to this exhibit.
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2023 ACTUAL AVERAGE USE TRUE-UP VARIANCE ACCOUNT
EGD RATE ZONE
1.The purpose of this evidence is to provide information in support of the 2023
Average Use True-up Variance Account (AUTUVA) balance.
2.Table 1 of Exhibit D, Tab 1, Schedule 4 details the calculations that result in a debit
from ratepayers of $14.307 million, plus interest of $0.786 million for a total debit
from ratepayers of $15.093 million. The collection is attributable to actual Rate 1
(residential) and Rate 6 (apartment, small commercial and industrial) average uses
being lower than 2023 forecast levels.
3.Lower weather-normalized average uses are primarily attributable to higher actual
natural gas prices and worse economic conditions in 2022 and 2023 than were
forecast. Higher gas prices have led to lower consumption for both Rate 1 and
Rate 6 customers. Lower GDP growth and high commercial vacancy rates than were
expected have been other factors which have also contributed to lower average use
for Rate 6 customers.
4.The purpose of the AUTUVA is to record (true-up) the revenue impact (exclusive of
gas costs) of the normalized volumetric difference between the forecast of average
use per customers in Rate 1 and Rate 6 and the actual weather-normalized average
use experienced during the year. The revenue impact is calculated using a unit rate
determined in the same manner as the impact used in the derivation of the Lost
Revenue Adjustment Mechanism (LRAM).
5.As detailed in Table 1 of Exhibit D, Tab 1, Schedule 4, the calculation of the
volumetric variance between forecast average use and actual normalized average
use subtracts the volumetric impact of Demand Side Management (DSM) programs
in the year. As has been the case in previous applications, since the audited actual
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volume savings of 2023 DSM activities will not be available until a later date an
estimate is used. Given the timing of the DSM Plan Proceeding, the 2023 DSM
volumes from Enbridge’s Application for Multi-Year Natural Gas Demand Side
Management Plan (2022 to 2027), EB-2021-0002, are used as an estimate of 2023
actuals. Without the exclusion of a DSM volumetric variance in the AUTUVA
calculation, the impacts of DSM are inherently included. As a result, 2023 LRAM
amounts which will be filed at a later date, will exclude the impact of Rate 1 and
Rate 6 customers.
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2023 DEFERRED REBATE ACCOUNT
EGD RATE ZONE
1.The purpose of the 2023 Deferred Rebate Account (DRA), consistent with prior fiscal
years, was to record any amounts payable to, or receivable from, EGD rate zone
customers as a result of clearing Deferral and Variance Accounts, which remain
outstanding due to the inability to locate such customers.
2.The balance in this variance account is a debit from EGD rate zones ratepayers of
$2.133 million, plus interest to December 31, 2023, of $0.187 million, for a total debit
of $2.320 million. The balance includes the residual amounts not disposed of from
the following deferral dispositions: 2021 Earnings Sharing and Deferrals (EB-2022-
0110) cleared effective January 2023, and 2021 Federal Carbon Pricing Program
(EB-2022-0194) cleared effective April 2023. The total forecast disposition balance
of these combined was a debit of $25.672 million, total recoveries were a credit of
$23.539 million, resulting in a net residual debit balance of $2.133 million. A
summary is provided in Table 1.
Table 1
Deferral Summary: Deferral Clearing Variance Account
Line
No. Proceeding
Amount
($ millions)
1 2021 Earnings Sharing and Deferrals (EB-2022-0110) 23.329
2 2021 Federal Carbon Pricing Program (EB-2022-0194) 2.343
3 Subtotal – Approved for Disposition in 2023 25.672
4 Amounts disposed of in 2023 through one-time billing adjustments (23.539)
5 Residual balance to Deferral Clearing Variance Account 2.133
3.The residual balance reflects the outstanding amount resulting from the clearance of
deferral and variance accounts in the EGD rate zone which occurred during 2023
and the inability to locate and dispose of the approved amounts to all intended
customers.
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Exhibit D
Tab 1
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2023 ONTARIO ENERGY BOARD COST ASSESSMENT VARIANCE ACCOUNT
EGD RATE ZONE
1.The purpose of the 2023 Ontario Energy Board Cost Assessment Variance Account
(OEBCAVA) was to record any material variances between the OEB costs assessed
to Enbridge Gas (relevant to the EGD rate zone) through application of the revised
Cost Assessment Model (CAM), which became effective April 1, 2016, and the OEB
costs which were included in EGD rate zone rates, which were determined through
application of the prior Cost Assessment Model. The scope of the account is
consistent with prior OEBCAVAs. However, in accordance with the EB-2020-0134
OEB-approved Settlement Proposal1, in Enbridge Gas’s 2019 Earnings Sharing and
Deferral Disposition proceeding, the base OEB costs assumed to be included in
rates have been escalated to the reflect the growth in the amount recovered through
rates, which results from annual price cap adjustments and customer growth. The
OEBCAVA was originally approved for establishment by an OEB letter dated
February 9, 2016, entitled: Revisions to the Ontario Energy Board Cost Assessment
Model.
2.The amount recorded within the 2023 OEBCAVA is $3.733 million, plus interest of
$0.302 million for a total debit balance of $4.035 million. This amount reflects the
variance between OEB costs assessed to Enbridge Gas (relevant to EGD rate zone)
in each quarter of fiscal 2023, utilizing the revised CAM, and EGD’s average
quarterly OEB cost assessment under the prior CAM, escalated in accordance with
the EB-2020-0134 OEB-approved Settlement Proposal.
3.In order to calculate the amount to be recovered through the 2023 EGD rate zone
OEBCAVA, the Company first needed to apportion the actual 2023 OEB assessed
costs between the legacy rate zones. Commencing with the OEB’s 2019 / 2020
fiscal first quarter assessment (for the period April 1, 2019 through June 30, 2019),
and continuing since, Enbridge Gas Inc. has been receiving one consolidated
1 EB-2020-0134, Decision on Settlement Proposal, January 25, 2021, pp. 5-6.
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quarterly bill for the amalgamated utility. To apportion the quarterly assessments
received in 2023 between rate zones, the assessments were prorated based on the
total invoices received by each legacy utility for the OEB’s 2018 / 2019 fiscal year
(for the period April 1, 2018 through March 31, 2019), the final year for which the
OEB issued invoices to each legacy utility. Table 1 below shows the proration of the
OEB’s 2018 / 2019 fiscal year assessments between each legacy utility / rate zone
(59.76% EGD rate zone, 40.24% Union rate zones). Table 2 shows the
apportionment of Enbridge Gas Inc’s 2023 assessed costs to the EGD rate zone,
and the calculation of the amount recorded in the 2023 EGD rate zone OEBCAVA.
4.To calculate the amount for recovery through the 2023 EGD rate zone OEBCAVA,
the Company also needed to establish the base comparator, reflecting the OEB
costs included in EGD rate zone rates, determined through application of the prior
Cost Assessment Model. In accordance with the EB-2020-0134 OEB-approved
Settlement Proposal, and methodology subsequently approved through the
EB-2021-0149, 2020 Earnings Sharing and Deferral and Variance Account
Clearance proceeding, the amount reflected in rates is to be increased, or escalated,
to reflect the growth in the amount recovered as a result of annual price cap
adjustments and customer growth. To establish the 2023 base comparator, the
Company escalated the 2022 quarterly comparator of $0.821 million by the sum of
the 2023 Price Cap Index (PCI) of 3.60%, and the EGD rate zone ICM threshold
calculation Growth Factor (g) of 1.19%. The 2023 PCI was approved as part of
Enbridge Gas’s 2023 Rate Application, EB-2022-0133. The 2023 ICM threshold
calculation Growth Factor was not filed as part of the 2023 Rate Application, as no
ICM funding was requested, but has been calculated using the same methodology
as the 2022 ICM threshold calculation Growth Factor, which was approved as part of
Enbridge Gas’s 2022 Rate Application, EB-2021-0147/0148. The escalation resulted
in a 2023 quarterly comparator of $0.861 million ($0.821 million * (1 + (3.60% +
1.19%))). As noted above, Table 2 below shows the apportionment of Enbridge
Gas’s actual 2023 assessed costs to the EGD rate zone, and the calculation of the
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Exhibit D
Tab 1
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amount recorded in the 2023 EGD rate zone OEBCAVA utilizing a base comparator
of $0.861 million.
5.Within this proceeding, the Company is requesting clearance of the principal and
interest balances recorded in the 2023 OEBCAVA, in the amount of $3.733 million
and $0.302 million respectively, as shown in Exhibit C, Tab 1, Schedule 1.
Table 2
Calculation of 2023 EGD RZ OEBCAVA
Line No. Period EGI Assessment
EGD Rate Zone Share (59.76%)
Average Cost assessment Comparator
Variance to
EGD Rate Zone OEBCAVA
1 Jan. 1 to Mar. 31, 2023 2,738,849.00 1,636,736.16 860,577.71 776,158.45
2 Apr. 1 to Jun. 30, 2023 3,141,892.00 1,877,594.66 860,577.71 1,017,016.95
3 Jul. 1 to Sep. 30, 2023 3,062,860.00 1,830,365.14 860,577.71 969,787.43
4 Oct. 1 to Dec. 31, 2023 3,062,860.00 1,830,365.14 860,577.71 969,787.43
5 12,006,461.00 7,175,061.10 3,442,310.85 3,732,750.25
Table 1
2018/2019 OEB Cost Assessments
Line No. Period EGD UGL Total
1 Apr. 1 to Jun. 30, 2018 1,467,963 988,479 2,456,442
2 Jul. 1 to Sep. 30, 2018 1,356,860 913,873 2,270,733
3 Oct. 1 to Dec. 31, 2018 1,356,860 913,873 2,270,733
4 Jan. 1 to Mar. 31, 2019 1,356,860 913,873 2,270,733
5 5,538,543 3,730,098 9,268,641
6 Percentage of Total 59.76% 40.24% 100.00%
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EB-2024-0125
Exhibit D
Tab 1
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Page 277
INCREMENTAL CAPITAL MODULE DEFERRAL ACCOUNT – EGD RATE ZONES
1.The Incremental Capital Module Deferral Account (ICMDA) records the difference
between the actual revenue requirement for approved ICM projects, and the
revenues collected through ICM rates approved by the OEB on a project-by-project
basis.
2.In the EB-2022-0200 Phase 1 Decision on Settlement Proposal dated August 17,
2023, parties agreed to the clearance of deferral and variance accounts as
proposed by Enbridge Gas including ICMDA balances. The balance approved at
the time was comprised of actual & forecast amounts. Enbridge Gas is seeking
final disposition of the remaining balance in the ICM Deferral Account in this
proceeding representative of the variance between the forecast balance approved
in the OEB approved Interim Rate Order dated April 11, 2024, and the final actual
balances as calculated through December 31, 2023.
3. The balance in this deferral account is a credit to the EGD Rate Zone of $4.909
million plus interest of $0.232 million for a total credit balance of $5.141 million.
The balance of $4.909 million represents the difference between the $2.031 million
debit approved for disposition in the Interim Rate Order and the calculation of the
final EGD Rate Zone ICMDA credit balance of $2.878 million as shown in Table 1.
4. The variance of $4.909 million the EGD Rate Zone projects is primarily the result of
a $3.7 million reduction in the Cherry to Bathurst Project revenue requirement due
to the timing of capital spend and project in-service date, as well as $1.3 million
additional revenue collected in rates compared to forecast.
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EB-2024-0125
Exhibit D
Tab 1
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Line
No.($000's)
(a) (b) (c)(d)(e)(f)(g) (h) (i)
Principal Interest Total Principal Interest Total Principal Interest Total
EGD Rate Zone
1.NPS 20 Don River Replacement Project - - - 79.2 13.2 92.4 79.2 13.2 92.4
2.NPS 20 Cherry to Bathurst Replacement Project 2,031.1 (247.7) 1,783.4 (2,957.1) (493.4) (3,450.4) (4,988.2) (245.7) (5,233.8) 3.Total EGD Rate Zone ICMDA 2,031.1 (247.7) 1,783.4 (2,877.9) (480.1) (3,358.0) (4,909.0) (232.4) (5,141.4)
Notes:
(1)
(2)Reflects 2019 through 2023 actuals.
(3)Represent variances between amounts approved for disposition in the Interim Rate Order and the final cumulative balances based on actuals.
EB-2022-0200 Rate Order, Working Papers, Schedule 27, pages 1 & 2; approved in Interim Rate Order dated April 11, 2024.
(EB-2022-0200)1 Final Cumulative Balances2 Amounts Proposed for Disposition
(2023 ESM and Deferral
Table 1
Summary of Incremental Capital Module Deferral Account
Amounts Requested for Clearance in 2023 ESM Proceeding
Actual & Forecast
Balances Approved for Disposition
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EB-2024-0125
Exhibit D
Tab 1
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Page 279
RENEWABLE NATURAL GAS (RNG) INJECTION SERVICE VARIANCE
ACCOUNT (RNGISVA)
1. The purpose of the RNGISVA is to record the annual revenue
deficiency/sufficiency related to the provision of RNG injection services to RNG
producers. The annual revenue deficiency/sufficiency will be calculated as the
difference between actual revenues generated under Rate 401 (RNG injection
service) and the actual revenue requirement impact of the costs incurred, on a fully
allocated basis, to provide those services. To ensure that ratepayers are not
harmed by potential default of Rate 401 customers, the annual revenue
deficiency/sufficiency calculation will not include any impacts of contract default by
RNG injection service customers.
2. In the EB-2022-0200 Rebasing Application, Enbridge Gas did not have adequate
certainty on the in-service timing of the RNG injection services, and furthermore
the preliminary forecast was less than $1 million. Given the uncertainty and
materiality, Enbridge Gas proposed bringing forth actual balances as part of the
2023 Utility Earnings and Disposition of Deferral & Variance Account Balances
proceeding1.
3. Enbridge Gas is seeking final disposition of the total balance in the RNGISVA
which is a cumulative credit to ratepayers of $0.332 million (see Table 1 for details)
plus interest of $0.029 million, for a total credit balance of $0.360 million.
1 EB-2022-0200 2024 Rebasing Application, Exhibit 9, Tab 2, Schedule 1, Section 5, para. 84.
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Exhibit D
Tab 1
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Table 1
Summary of RNGISVA Amounts Requested For Clearance
Line
No. ($000’s) 2022 2023
1 Revenue Requirement - Dufferin Injection (77.1) 515.2
2 Annual Service fee - Dufferin Injection 82.1 687.5
3 Annual Sufficiency/(Deficiency) 159.2 172.3
4 Cumulative Sufficiency/(Deficiency) 159.2 331.5
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EB-2024-0125
Exhibit D
Tab 1
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ACCOUNTS WITH A ZERO BALANCE - EGD RATE ZONE
1.The following 2023 accounts for the EGD Rate Zone have no balance, and are
therefore not requested for clearance to customers:
•Gas Distribution Access Rule Impact (GDARIDA) Deferral Account;
•Electric Program Earnings Sharing (EPESDA) Deferral Account
•Pension and OPEB Forecast Accrual vs. Actual Cash Payment Differential
Variance Account;
•Open Bill Revenue (OBRVA) Variance Account;
•Ex-Franchise Third Party Billing Services (EFTPBSDA) Deferral Account;
•Dawn Access Costs (DACDA) Deferral Account; and
•Transition Impact of Accounting Changes (TIACDA) Deferral Account.
2.Consistent with past annual deferral and variance account clearance proceedings,
Enbridge Gas has not listed accounts that will be reviewed through other processes in
Exhibit C, Tab 1, Schedule 1, and these accounts are not addressed in this proceeding.
Examples include the Purchase Gas Variance Account (PGVA), DSM related accounts
and Federal Carbon Charge accounts.
3.The balance in the Transition Impact of Accounting Changes (TIACDA) Deferral
Account remaining after the clearance of the 2022 amount was approved for disposition
as part of the OEB’s EB-2022-0200 Interim Rate Order approved on April 11, 2024.
Therefore, there will be no further balance to dispose of in this account.
Filed: 2024-05-31
EB-2024-0125
Exhibit D
Tab 1
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2024-05-21 Final Report
Team
Heather Isidoro – Highwood Emissions Management
Brendan Moorhouse – Highwood Emissions Management
Bruna Goes Palma – Highwood Emissions Management
Thomas Fox – Highwood Emissions Management
Prepared for
Disclaimer Highwood Emissions Management Inc. (Highwood) has prepared this report for Enbridge Gas Inc. based on
an agreed scope of work. The report was commissioned by and prepared for the exclusive use of Enbridge
Gas Inc Except where expressly stated, Highwood cannot guarantee the validity, accuracy, or
comprehensiveness of any information presented in this report. Information presented in this report may be
used to guide decision making but additional information or research may be required. While every effort is
made by Highwood to ensure that accurate information is disseminated through this report, Highwood
makes no representation about the content and suitability of this information for any purpose.
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Table of Contents
1. Executive Summary .............................................................................. 3
2. Glossary ............................................................................................... 4
3. Introduction ......................................................................................... 9
4. Background ........................................................................................ 11
5. Overview of Methane Emission Reporting Methods ............................ 16
6. Methane Detection and Measurement Technologies .......................... 32
7. Current EGI Methane Emissions Inventory and Management Analysis . 41
8. Technology Deployment Scenario Analysis.......................................... 60
9. Recommendations and Implementation Plan for Enbridge .................. 95
10. Conclusions .................................................................................... 102
11. Appendix ........................................................................................ 104
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1. Executive Summary
Enridge Gas Inc. (EGI), Canada's largest natural gas storage, transmission, and distribution company,
has committed to developing a plan for improving the accuracy of its reported fugitive emissions as
part of the partial settlement proposal that was filed with the Ontario Energy Board (OEB) on June 28,
2023, as part of its 2024 Rates Application. Highwood Emissions Management (Highwood) conducted
a comprehensive assessment of EGI’s 2022 inventory and practices and provided recommendations
for technology deployment strategies to improve emissions accuracy.
The report begins with an overview of greenhouse gas emissions, EGI's business segments, and the
regulatory frameworks governing emissions reporting in Canada. It discusses various emissions
quantification methodologies, including bottom-up inventories and measurement-informed
inventories (MII), and highlights the importance of uncertainty estimation and mitigation strategies.
A key focus of the report is on technology options for detecting and quantifying fugitive emissions. It
covers a range of commercial methane (CH4) detection technologies, deployment platforms, sensing
principles, and controlled release testing methods. The emphasis is on selecting accurate, efficient,
and compliant technologies that meet the unique needs of storage, transmission, and distribution
operations.
EGI's current fugitive emissions inventory and calculation methodologies are reviewed, including
materiality assessments and year-over-year trends. The report provides insights into higher-emitting
sources, station sizes, and contribution analysis across storage, transmission, and distribution
operations.
Highwood presents this report and recommendations to support EGI in increasing the accuracy of
their fugitive emissions inventory. Highwood recommends that EGI initiate pilots to begin
implementing a measurement strategy and to begin developing company-specific emission factors to
complement or replace generic emission factors. Increased detection and measurement data will
increase the accuracy of both the quantity and frequency (or presence) of fugitive emissions and
displace generic emission factors, which will better represent EGI’s asset base. Highwood does not
recommend the deployment of aerial and satellite technologies on EGI’s systems based on their
current performance but recommends monitoring future development and pilot opportunities for
aerial technology.
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2. Glossary
Activity Factor (AF) -Typically refers to the population of emitting equipment. For example, activity
factors could refer to kms of natural gas pipeline, the count of thief hatches on a facility or the
mechanical power of gas turbines. Activity factor can also refer to other parameters that directly
influence the rate of operation and therefore emissions. For example, the activity factor for
combustion engines can be the amount of fuel consumed or the number of operating hours.
Aggregated Data: Emissions data collected from multiple sources and combined, usually for
reporting or statistical analysis.
Anthropogenic - Of, relating to, or resulting from the influence of human beings on nature.
Audio, Visual, and Olfactory (AVO) surveys - Audio, visual, and olfactory (AVO) surveys are a type of
methane detection survey performed using human senses. Regulations often have some form of AVO
requirement that is equipment or site specific.
Bottom-up Emissions Inventory - A list of emission sources by category and quantity, providing
detailed information on individual sources. Bottom-up inventories can use generic emission factors
derived from industry averages, company specific emission factors, direct measurements,
engineering calculations, or manufacturer data.
Bottom-up Measurement: A measurement that occurs at a granular scale (e.g., component) used to
estimate emissions more broadly. Bottom-up measurements can be averaged into emission factors
and combined with activity factors to build a bottom-up inventory.
Component - Multiple components (e.g., valves, flanges, and threaded connections) comprise
equipment (e.g., tanks, separators) and a site may have multiple pieces of equipment or equipment
groups. In LDAR-Sim, a component is the smallest scale of oil and gas infrastructure that can be
modeled.
Detection – The determination by a method or device that methane levels are above ambient
background concentration. In some cases, this may be an indication of a leak or an emission.
Distribution - The segment of the natural gas value chain comprised of pipelines and metering and
regulating equipment, used to deliver natural gas to end-use consumers.
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Downstream - The final stage in the oil and gas value chain. Activities include distribution, retail
marketing, product development, and consumption by the end user.
Emission Factor - Describes typical methane emissions per unit of activity of a component or part of
the gas system (e.g., valve, pipeline section) or from an event and can have units like [kg/km],
[kg/event], [kg/time], or [kg/equipment]. Emission factors are typically expressed in mass rate units
[kg/hr], [kg/km/year], [kg/equipment/hr]i. Emission factors can be generic or company specific.
Emissions Inventory – Generally refers to a database that lists the amount of air pollutants
discharged into the atmosphere during a year, by source, and can include categories such as
combustion, venting, flaring, and fugitives.
Flaring - An intentional, controlled burning of natural gas. Gas is ignited at the top of a flare stack,
creating a characteristic flame.
Follow-up survey - An inspection to confirm or deny potential leaks detected through a screening
survey. Typically, screening technology will identify a potential leak at the site or equipment-scale.
Follow-up surveys diagnose leaks at the component scale, typically with handheld detection
methods.
Fugitive Emissions - The unintentional release of hydrocarbons to the atmosphere. These emissions
can occur due to leaks or third-party damages.
Fugitive Emissions Measurement Plan (FEMP) – In this report, “FEMP” refers to the Fugitive
Emissions Measurement Plan that will be developed by Enbridge Gas.
Note: The Alberta Energy Regulator uses the acronym “FEMP” to refer to a “Fugitive Emissions
Management Program” In the U.S. and elsewhere, the term 'LDAR Program' is often used.
Greenhouse Gas (GHG) - A gas that traps heat in the atmosphere, such as carbon dioxide, methane,
nitrous oxide, and fluorinated gases.
Handheld Instrument - A small, portable methane detection instrument that is often used to detect
and diagnose leaks at the component scale. Examples include optical gas imaging (OGI) cameras and
handheld organic vapor analyzers (OVAs).
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LDAR - Leak detection and repair (LDAR) are the work practice and execution of identifying leaking
equipment and conducting repairs. A component subject to LDAR requirements must be monitored at
specified, regular intervals to determine if it is leaking. Often, regulatory requirements specify a repair
timeline, which may be related to leak size and severity.
Leak - The unintentional release of hydrocarbons to the atmosphere. A component of fugitive
emissions.
Measurement - Quantification of emissions mass or volume rates from data collected directly from
the environment at a specific place and time. Measurements can be used to inform bottom-up or top-
down inventories.
Measurement-Informed Inventory (MII) – An emissions inventory that incorporates company-
specific measurements and that does not rely exclusively on generic assumptions. Various regulatory
and non-regulatory guidance exist for the development of MIIs. These can differ in their requirements.
For example, OGMP 2.0 Level 4 is a MII in which company-specific measurements, engineering
estimates, and/or simulations are used at the source level for material sources. Veritas Pathways 1
and 2 provide methodologies to develop MIIs that rely on site level measurements extrapolated across
space and time. Most MIIs do not require exclusive use of measurements but encourage operators to
minimize use of generic inputs.
Methane - A colorless, odorless gas that occurs abundantly in nature and as a product of certain
human activities. Its chemical formula is CH4.
Midstream - The segment in the oil and gas value chain following that falls between upstream and
downstream. Activities include transmission and storage.
Minimum Detection Limit - The smallest atmospheric concentration or emission rate that a
technology is capable of discerning above background.
Probability of detection is the likelihood that a measurement method will successfully detect the
presence of a target species such as methane gas in the atmosphere. For example, a technology with
detection sensitivity of 10 kg/hr with 90% PoD means that, for given environmental and operational
parameters, the technology solution will statistically detect at least 9 out of 10 leaks that are 10 kg/hr.
The POD may vary with environmental conditions.
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Natural Gas: Natural gas is a naturally occurring and flammable hydrocarbon gas used for fuel. Its
primary component is methane (CH4), but it can also contain ethane, propane, butane, and pentanes.
Often, impurities including oxygen, hydrogen sulfide (H2S), nitrogen, water, and carbon dioxide are
also present.
Optical Gas Imaging (OGI) - A common leak detection technology that uses thermal infrared cameras
to visualize methane and various other organic gases. Common OGI cameras create images of a
narrow range of the mid-IR spectrum (3.2− 3.4 μm wavelength) which methane and other light
hydrocarbons actively absorb.
Parametric Data - operational data and characteristics utilized to inform inventories including
production rates, equipment specifications, performance characteristics, gas composition, and
process parameters.
Quantification - Determining an emission rate, such as mass per time or volume per time. This can be
done directly through measurement of the emissions, or indirectly through estimations, calculations,
and modeling.
Quantitative Optical Gas Imaging (QOGI) - Combines optical gas imaging (OGI) camera technology
with cross-section pixel absorption algorithms to quantify emissions. The brightness of each pixel
seen through the OGI camera is proportional to the amount of infrared radiation incident on the
camera along the corresponding line of sight through the plume. The brightness is converted to a
concentration and combined with estimated velocities to obtain mass fluxes.
Screening Survey - LDAR screening methods are used to rapidly flag high-emitting sites to direct
close-range follow-up source diagnosis and root cause analysis. An example of a common screening
method is an aerial monitoring campaign.
Transmission - Natural gas transmission systems move natural gas from upstream gathering,
processing, or storage facilities to distribution systems, large-volume customers or other
storage/processing facilities.
Unaccounted for Gases (UFG) - The difference between gas receipts and gas deliveries, where gas
receipts are volumes that enter a pipeline system and gas deliveries are volumes that exit the pipeline
system. In the case of Enbridge Gas’s regulated distribution assets: receipts include (but are not
limited to) volumes of gas received into the distribution system from various interconnects, including
upstream pipelines, underground storage, and local supplies/production; deliveries include (but are
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not limited to) volumes of gas delivered from integrated storage, transmission, and distribution
systems to various interconnects, including downstream pipelines, underground storage, and to end-
use customers.
Upstream - The first segment in the oil and gas value chain, consisting of exploration and production
processes. Activities include drilling, production, and processing.
Vented Emissions - The controlled release of unburned gases into the atmosphere, such as natural
gas or other hydrocarbon vapors.
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3. Introduction
In June 2023, a commitment was made by Enbridge Gas Inc. (EGI) to investigate and determine an
appropriate way to accurately measure fugitive emissions, as part of a partial settlement proposal in
EGI’s 2024 Rebasing application (EB-2022-0200). The report will include an analysis of EGI’s current
emissions inventory and give recommendations on how to improve the accuracy of reported fugitive
emissions.
3.1. Partial Settlement Proposal
On June 28, 2023, in EB-2022-0200, EGI filed a partial settlement proposal with the Ontario Energy
Board (OEB). In this proposal, EGI agreed to investigate a way to accurately quantify fugitive
emissions:
"In relation to fugitive emissions, which are a component of UFG, Enbridge Gas has
agreed to investigate and determine an appropriate way to accurately measure
fugitive emissions, including consideration of top-down measurements (i.e., by
aircraft, satellite, and/or towers), with the goals of:
(a) confirming the volume of fugitive emissions,
(b) determining if recent UFG increases could be due to fugitive emissions, and
(c) attempting to locate specific fugitive sources that can be mitigated. This would
include all kinds of assets (transmission, rural & urban distribution, and storage).
Enbridge Gas will file a robust investigation plan for consideration and determination
in the 2024 deferral and variance account proceeding, which filing shall include
justification of the planned approach, including, without limitation, whether it will
include aerial (i.e., top-down) investigation. "
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3.2. Objectives and Approach
The objective of this report is to assess EGI’s current fugitive inventory and make recommendations
for appropriate strategies and technology deployment options to increase the accuracy of reported
fugitive emission volumes. EGI contracted Highwood Emissions Management (Highwood) to prepare
this report to support EGI’s submission to the OEB.
This report provides background on Greenhouse Gas (GHG) emissions and EGI’s business segments.
This report also provides an overview of regulatory frameworks, emissions quantification and
estimation methodologies, and uncertainty. An overview of technology options and operating
parameters is provided to give context to the analysis and recommendations. Highwood’s review
included:
• A review of EGI’s year-over-year total emissions, identifying any notable increases or
decreases,
• A materiality assessment to look at which sources have the highest contribution to emissions,
to provide focus on the most impactful emitters,
• A review of current calculation methodologies and measurement and detection practices
considering current regulatory frameworks,
• A review of technology deployment scenarios to determine optimum deployment strategies
available across each EGI business segment and
• Recommendations on technology deployment strategies to increase the accuracy of fugitive
emissions.
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4. Background
This section defines GHG emissions and provides an overview of contributing gases. It includes an
explanation of reporting units and an introduction to the Global Warming Potential (GWP) of methane,
noting the significance of how adjusting the GWP number impacts overall reported emissions.
This section also gives an overview of EGI’s transmission, storage, and distribution segments, noting
the distinct components of each segment and the operational size and magnitude of key operational
infrastructures. Specific sources of GHG emissions in EGI’s operating areas and their significance
relative to other sources of emissions will also be discussed.
4.1. Greenhouse Gas Emissions
GHGs are gases that trap heat in the atmosphere and include carbon dioxide (CO2), methane (CH4),
nitrous oxide (N2O), and fluorinated gases (F-gases). GHGs can be classified as natural, which are
found in nature, or anthropogenic, which are man-made.
Natural GHGs are emitted through natural processes such as volcanic eruptions, wildfires,
decomposition of organic matter, and biological processes in plants and animals.
Anthropogenic emissions are emitted through the combustion of fossil fuels, industrial processes,
deforestation, agriculture, and waste management. According to the Intergovernmental Panel on
Climate Change (IPCC)ii, anthropogenic sources are estimated to contribute around 50-60% of total
global GHG emissions. Anthropogenic emissions can be intentional (i.e., operational releases such as
venting) or unintentional (i.e., fugitive emissions).
The Joint Research Center estimates that CO2 and CH4 account for approximately 71% and 21%,
respectively, of 2022iii global anthropogenic GHGs (Figure 1).
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Figure 1: Anthropogenic greenhouse gas emissions breakdown
CO2 is produced by the combustion of fossil fuels. CO2 can also be produced by solid waste,
biological materials, and because of certain industrial chemical reactions (e.g., cement production).
CH4, the main component of natural gas, is produced during fossil fuel extraction (coal, natural gas,
and oil) and distribution, agricultural practices, land use, and by the decay of organic landfill waste.
Any leakage along the value chain or release constitutes a direct emission of CH4 into the atmosphere
and is often referred to as a fugitive emission.
Global Warming Potential (GWP) was developed to allow comparisons of the impacts of different
gases on global warming. Specifically, GWP reflects other greenhouse gas’s ability to trap heat in the
atmosphere compared to CO2. The larger the GWP, the more significant the impact is on climate
change. CH4 has a GWP of 27-30 over 100 years and 81-83 over 20 yearsiv, subject to revisions to the
Intergovernmental Panel of Climate Change Assessment Reports. This means the impact of methane
emissions can be 27-83 times greater than CO2, depending on the chosen time horizon.
GHG emissions can be expressed in volume or mass, most commonly in tonnes of a specific gas.
When multiplied by the GWP, the result allows for a comparison between each of the gases and is
expressed in tonnes of CO2 equivalent, or tCO2e (Table 1). For the purposes of this report, all
emissions are expressed in tCO2e.
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Table 1. The effect of the GWP when comparing CO2 to CH4 in CO2e for AR5 100-year time horizon
CO2 CH4
Mass (tonnes) 1 1
GWP 1 28
Mass (tCO2e) 1 28
% Contribution based on tCO2e 3% 97%
Fugitive emissions represent the unintentional release of GHGs, including CH4, into the atmosphere.
For the purposes of this report, fugitive emissions are defined as leaks from the natural gas system or
gas losses due to third-party damages.
In natural gas systems, unaccounted-for gas reflects the imbalance that exists at any given time
between the measured gas coming into the system and the measured gas exiting the system.
Fugitive emissions make up just one of several potential contributors to unaccounted-for gas and refer
specifically to the unintended releases of gases from equipment leaks or emissions from third party
damages.
4.2. EGI Business Segment Overview
EGI is Canada’s largest natural gas storage, transmission, and distribution companyv. EGI serves
approximately 3.9 million customers in Ontario and Quebec, distributes about 2.3 billion cubic feet
(Bcf) per day of natural gas, and has an effective peak demand capacity of 7.6 billion cubic feet (Bcf) of
natural gas. EGI operational segments can be categorized by: Storage and Transmission Operations
(STO) and Distribution Operations (DO).
EGI’s STO network consists of transmission systems and gas storage facilities. The storage and
transmission system consists of 4700 kilometres (km) of pipelines, 22 compressor stations, as well as
other supporting infrastructure, including receipt stations, valve stations, farm taps, and batteries
(Table 2).
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Table 2. EGI system parameters for transmission and distribution
Storage and Transmission
Net Storage Working Capacity 291.6 Bcf (billions of cubic feet)
Transport Capacity 11,239,121 GJ
Compressor Stations 22 count
Wellheads 399 count
Transmission Pipeline 4,707 km
Distribution
Service Pipeline 68,389 km
Main Pipeline 74,547 km
Customer Meter Sets 3,940,632 count
Gate Stations 465 count
EGI’s storage facility at Dawn is the largest facility of its kind in Canada, with a working capacity of over
284 Bcf in 34 facilities utilizing depleted gas fields. The storage system consists of compressor
stations, storage metering sites (receipt/sales meter stations), storage wells, and associated
gathering lines.
EGI’s DO segment provides natural gas to residential, commercial and industrial customers. The
operational infrastructure consists of over 105,000 km of pipelines, distribution stations, and 3.9M
customer meter sets (Table 2).
Much of EGI’s natural gas distribution network is located within populated urban areas, including the
greater Toronto area (GTA) and Ottawa. The network also services southwestern Ontario, expanding to
the North (Figure 2).
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Figure 2: Map of EGI's service areas in Southern Ontario
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5. Methane Emissions Reporting Methods
5.1. Introduction
In Canada, CH4 reporting requirements for storage, transmission, and distribution are governed by
various regulatory frameworks and reporting requirements established by federal and provincial
authorities.
In this section, we provide an overview of the regulatory frameworks and industry-specific practices
applicable to EGI and the quantification and reporting methodologies within those frameworks. We
also describe a broad range of approaches, including bottom-up and top-down methods and
introduce the concept of measurement-informed inventories (MII). We also discuss sources of
uncertainty, the main types of uncertainty, and mitigation strategies.
5.2. Regulatory Frameworks
In this section, we provide an overview of regulatory frameworks and reporting methodologies for GHG
emissions in the natural gas transmission, storage, and distribution sectors in Canada.
5.2.1. Federal Regulations
The key frameworks that regulate GHG emissions and reporting are Canada's federal Greenhouse Gas
Reporting Program (GHGRP), and the Regulations Respecting Reduction in the Release of Methane
and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector).
GHGRP
Canada's Greenhouse Gas Reporting Program (GHGRP) is administered by Environment and Climate
Change Canada (ECCC). The program requires companies with emissions above a certain threshold
to report them annually to ECCC. GHGRP provides guidelines and methodologies for reporting
greenhouse gas emissions, including CH4. Canada’s Greenhouse Gas Quantification Requirements
(GGQR) provides technical guidance for those required to report information to ECCC under the
GHGRP. The GGQR includes an overview of quantification methods and provides generic emission
factors for use when facility-specific factors are not available. EGI’s natural gas storage,
transmission, and distribution system is subject to reporting requirements under the GHGRP if
emissions exceed 10,000 tonnes of CO2e per year.
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Federal Methane Regulations (Regulations Respecting Reduction in the Release of Methane and
Certain Volatile Organic Compounds (Upstream Oil and Gas Sector)
The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic
Compounds (Upstream Oil and Gas Sector) introduced emissions thresholds (facility and equipment
level standards) to reduce fugitive and venting emissions of hydrocarbons, including methane, from
applicable facilities. Proposed amendments to this regulation, introduced in early 2024, build upon
the existing Regulations to further reduce methane emissions through more frequent leak surveys,
shorter repair timelines and more stringent venting and flaring requirements.
5.2.2. Provincial Regulations (Ontario)
Provinces in Canada have unique regulatory frameworks and reporting requirements related to GHG
emissions. Ontario facilities which exceed the 10,000 tCO2e emissions threshold must report
emissions annually under Ontario Regulation 390/18. Facilities must follow the standard
quantification methods as set out in the Guideline for Quantification, Reporting and Verification of
Greenhouse Gas Emissions (the Ontario Guideline), which references emission factors and
methodologies published in the Canadian Energy Partnership for Environmental Innovation (CEPEI)
Methodology Manual. Ontario emitters are also required to register and report applicable emissions
under Ontario’s Emissions Performance Standards (EPS) program, under Regulation 241/19. Under
the EPS program facilities engaging in natural gas transmission and storage require verification of
applicable emissions by an accredited verification body.
5.2.3. Industry Best Practices and Guidelines
Industry associations and organizations in Canada, such as the Canadian Energy Partnership for
Environmental Innovation (CEPEI), develop best practices and guidelines for CH4 calculation and
reporting.
CEPEI publishes an annual Air Emissions Methodology Manual to assist companies in quantifying
atmospheric emissions from fugitive, venting, flared and combustion sources at Canadian natural gas
transmission, storage, and distribution facilities. The manual facilitates a complete accounting of
atmospheric emissions, including CO2, CH4, and N2O. The emission factors for fugitive equipment
leaks and venting provided in the CEPEI manual are primarily based on measurement studies
sponsored by the Canadian and/or US natural gas industry. This manual is included as a Technical
Reference Document in Ontario’s Guideline for Quantification, Reporting and Verification of
Greenhouse Gas Emissions.
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5.3. Emissions Quantification Methodologies
There are several recognized methodologies for calculating fugitive emissions. These range from using
published generic emission factors to developing company-specific emission factors and completing
site-level measurement campaigns for top-down reconciliation. All methods incorporate
measurement data, parametric data, and activity data (operations data such as km of pipeline and
equipment counts) in different ways.
An emission factor is a value that relates the typical emissions per unit of activity (such as a
component or event) occurring within a gas system. In most cases, emission factors are averages of
all available data of acceptable quality and are generally assumed to be representative of long-term
averages for all facilities in the source category.
A “bottom-up” inventory of emissions involves compiling an inventory of equipment and components
and estimating the associated emissions for those components. Bottom-up inventories can be
developed using generic emission factors, company-specific emission factors, or direct
measurements.
“Top-down” measurements aggregate multiple potential sources into a single estimate and may be
site level (consisting of all equipment groups on site), or regional (consisting of all sites in a
measurement area. Top-down estimates can be developed without knowledge of the source-level
inventory. There is significant value in comparing and reconciling the two estimates. Understanding
the differences can provide significant insights into the accuracy of the emissions inventory and can
result in an improved emissions inventory. Both bottom-up and top-down approaches may be used for
building emissions inventories (Table 3).
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Table 3: Overview of potential emissions estimation techniques for building inventories Bottom-Up Approach Generic Emission Factors: Generic emission factors are average emission rates for
a given component, generally derived based on industry measurement campaigns
and used with activity factors. Generic EFs assume typical steady-state leak rates
and typical frequency of intermittent leak rates across a range of equipment,
maintenance activities, and equipment malfunctions. These factors provide a
straightforward way to estimate fugitive emissions without site-specific
measurements. While generic emission factors represent the leak rate per
component type considering the entire population of components (i.e. “population
average factor”), leaker emission factors represent the leak rate per component
considering leaking components only (i.e. “leaker factor”). Generally, the more
representative an emission factor is of the actual operating conditions it is being
applied to, the more accurate it is.
Company-Specific Emission Factors: Company-specific emission factors are
developed based on direct measurement of a representative sample of company
assets. These factors reflect the emissions associated with the company's unique
operational characteristics and components.
Direct Measurement: Leak flow rate can be directly measured using technologies
such as hi-flow samplers by performing a survey of all assets of a given type. With
direct measurement, activity factors are not required. Top-Down Top-Down Measurement: Top-down measurements are typically done at a site or
regional scale. Activity factors are not required or used with top-down
measurement.
Top-down measurements can be used to complement and verify bottom-up inventories.
Reconciliation is a process whereby top-down measurements are combined with a bottom-up
inventory to develop a more accurate emissions estimate. A reconciliation can be used to help identify
discrepancies and refine emission estimates. In some cases, where discrepancies between the
bottom-up inventory and the site-level measurements are identified, site-level measurements may be
added to the bottom-up inventory if they cannot be explained. For example, a site-level measurement
may reveal a previously unknown emission source, in which case, the operator may choose to add the
measured volume to their inventory to account for that source. In other instances, there may be
alignment between the sources in the bottom-up inventory and the site-level measurement.
The selection of an appropriate emissions estimation methodology should consider:
• The objective of the emissions inventory
• Data availability
• The contribution of a given emission source to the overall inventory (materiality)
• The cost and practicality of the emission estimation method
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Combining multiple methodologies or using a tiered approach can enhance the accuracy and
reliability of CH4 emission estimates.
The advantages and disadvantages of each methodology are presented in Table 4. Advantages and
disadvantages of different emissions estimation techniques for building inventories, with
consideration given to:
• Level of effort
• Cost
• Uncertainty
• Resource implications (requirements for each methodology noting, however, options exist to
outsource to third-party providers)
The specific cost data of each methodology depend on individual contracts between operators,
technology providers, site-specific parameters, frequency, work practices, asset density, and other
factors. Therefore, specific cost data is not included in the table below.
Table 4. Advantages and disadvantages of different emissions estimation techniques for building inventories
Methodology
Advantages Disadvantages
Generic Emission Factors
• Provides a rapid estimation of emissions
without the need for site-specific emissions
measurements.
• Sometimes derived from measurements from
a larger sample population than a single
operator might measure, providing a more
representative statistical average.
• Least resource and cost intensive method –
does not require annual surveys.
• May not accurately reflect emissions arising
from a specific company’s current operating
practices.
• Generic factors may not capture uncertainty
due to technology, practices, or regional
differences unique to a specific operator.
Company-Specific Emission Factors
• Can more accurately reflect the company’s
emissions, unique characteristics, variations
and operating conditions compared to
Generic EFs.
• Can be used to validate previous emissions
reduction initiatives and actions.
• Can help identify trends and opportunities to
reduce emissions based on the company’s
unique asset profile and characteristics.
• Developing and maintaining company-
specific emission factors requires more
resourcing than using generic EFs since
company-specific measurements are
required.
• Requires effective site stratification to
develop representative EFs.
• Insufficient statistical sampling strategies or
sample sizes could impact accuracy or
contribute to uncertainty.
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• Less cost and resource intensive than full
system measurement. Does not require
system-wide measurement – EFs are
developed by measuring a representative
sample of assets.
• Increased costs over generic EFs, as a
sampling and measurement survey plan
must be performed.
Direct Measurement
• Generally considered to provide high
accuracy CH4 concentrations
• Allows for more accurate determination of
frequency and size of leaks, as well as
changes in CH4 levels.
• Standardized calibration and measurement
protocols help maintain consistency and
comparability of data across asset ranges.
• Can be expensive to purchase, operate and
maintain measurement equipment, or hire
third-party service providers.
• Direct measurement methods may have
limitations in sampling certain environments
or sources of CH4, such as remote locations,
confined spaces, or areas with limited
access to the source (road versus foot
access).
• The highest resource requirements for the
bottom-up methods. Can be outsourced to a
3rd party.
Top-Down Measurement
• emissions can be measured over large
geographic areas in relatively short
timeframes.
• Can provide insights on unexpected
emissions, e.g., significant but rare leaks that
have not been identified in a bottom-up
approach.
• Provides validation of bottom-up estimates.
• Allows for more accurate determination of
frequency and size of leaks, as well as
changes in CH4 levels.
• Top-down technologies generally have higher
minimum detection limits (MDLs) and lack
the spatial resolution to capture smaller
leaks.
• technologies only provide a ‘snapshot’ in
time that must be extrapolated to the
reporting period using models (e.g., OGI, gas
chromatography, stack testing)
• Challenging to identify the sources of
measured emissions (e.g. anthropogenic CH4
vs. company leaks)
• It can be expensive to purchase, operate, and
maintain measurement equipment or
outsource.
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5.4. Measurement Informed Inventories
A Measurement-Informed Inventory (MII) is an emissions inventory that leverages company-specific
data and that does not rely exclusively on generic assumptions. Various regulatory and non-regulatory
criteria exist. For example, OGMP 2.0 Level 4 specifies reporting requirements that would produce an
MII inventory in which company-specific measurements, engineering estimates, and/or simulations
are used at the source level for material sources. Veritas Pathways 1 and 2 provide approaches for
obtaining measurements that can be used to develop MIIs. Most MIIs do not require the exclusive use
of measurements but encourage operators to minimize the use of generic inputs. The goal of an MII is
to improve confidence and defensibility of CH4 emission estimates and prioritize emissions mitigation
efforts. MIIs can be valuable for effectively allocating resources to emissions mitigation projects,
supporting companies in achieving reduction targets and demonstrating progress with confidence.
Bottom-up inventories have commonly been based on generic emission factors. In its most basic
form, a MII can be calculated in the same way as a generic bottom-up inventory, but with company-
specific data such as company-specific emission factors or direct methane measurements used in
place of generic assumptions. More rigorous MIIs can leverage multiscale measurements, such as
aerial top-down surveys followed up with source level ground-based measurements to validate or
improve bottom-up inventories via reconciliation. More rigorous MIIs also use a higher proportion of
measurements relative to generic assumptions and adequately constrain uncertainty in those
estimates.
While current regulatory requirements in Canada do not require reconciliation of different emissions
estimates, several voluntary initiatives do. Initiatives including GTI Veritas, MiQ, and OGMP 2.0
consider integration of top-down and bottom-up measurements to be more robust than inventories
which are built using only one methodology, since a multiscale measurement campaign allows one
scale of measurement to validate the other.
5.5. Site Stratification and Sampling Guidance
The goal of a site stratification exercise is to determine reasonable site categorizations that can be
used as the basis for a sampling strategy, and extrapolation of site-specific emission factors across
unmeasured sites. Site stratification should be an iterative improvement process.
Once groupings and sub-groupings are determined, a representative sample size should be chosen
that balances population representativeness with feasibility and resource availability. OGMP2.0vi
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provides an example of guidance on balancing materiality with population sizes (Figure 3). Blue
represents a low materiality, and red represents a high contribution to materiality.
Figure 3: OGMP2.0 site sampling matrix
OGMP2.0 guidance notes that pipe segments, meter runs and pressure regulating stations are
generally classified as simple sites/facilities in that they would be expected to have low variability in
emissions. OGMP2.0 also notes that directionally, as population increases, the percentage of sites
requiring measurement lowers. As population sizes increase into the mega-population size, sampling
feasibility can become challenging, however, OGMP is only one guidance reference point. Other
examples of statistical methods to determine sample size exist, such as those in the recent study
published by Newton et al..vii
Once a sampling plan is determined based on materiality and available resources, a measurement
technology can be scheduled for deployment. Results can be aggregated and assessed across each
subcategory sample population and extrapolated to inform company specific emission factors.
Developing company-specific emission factors should be an iterative and evolving process. As
emissions measurements are performed and data is gathered, trends and anomalies should be
identified, and mitigation resources can be strategically deployed. Operators can reclassify as needed
and adjust subsequent survey plans based on results and impact on inventory. For example, if there
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are high levels of consistency across a given source, operators can consider focusing on a smaller
sample size the following year or pivoting resources to another high-materiality source category.
Increasing or adjusting programs to refine company-specific emission factors can increase the
accuracy of reported emissions and add validity to the overall quantification process, as well as the
results of mitigation efforts.
5.6. Company Specific Emission Factors
Generic emission factors are generally representative of like assets but do not represent the specific
characteristics of a company’s unique operating parameters, such as maintenance, replacement
procedures or preventive policies.
To displace generic emission factors, company specific sampling programs can be utilized to develop
company-specific emission factors. The sampling guidance noted in Section 5.3.2 from OGMP2.0 can
be used as guidance for sampling a test area to help inform sample set determinations. Existing
asset/source classifications can be used, as well as initial groupings of assets alongside features that
may provide distinct groupings. Groupings and sub-grouping can be based on populations of
sites/facilities (production batteries, pipeline segments, compressor stations, meter set, etc.) or by a
population of sources (equipment type, operating status, process).
The Veritas Measurement and Reconciliation Version 2.0viii guidance notes that “in the distribution
segment, most emissions sources are amenable to measurements for purposes of estimating annual
inventories.” The protocol provides guidance on categorizing assets and then stratifying sources and
groups of assets to inform a sampling strategy. Step 8 in the protocol, Reconcile Inventories and
Estimate Measurement Informed Inventory, gives comprehensive guidance on extrapolating and using
measurement results to inform non-surveyed areas. For sample size guidance, Veritas references the
OGMP 2.0 guidance, as noted in Section 5.3.2.
5.7. Uncertainty
Uncertainty estimates are an important element of a complete inventory of greenhouse gas
emissions. Uncertainty associated with methane emissions refers to the level of confidence in
reported CH4 emissions and characterizes the dispersion of values that could reasonably be
attributed to the measurement.
The three main sources of uncertainty are:
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• Technology performance
• Sampling strategy
• Extrapolation (temporal and spatial)
Within the three main sources of uncertainty, the following are some of the specific contributors:
• Technology
• Detection capabilities (probability of detection)
• Emission rate quantification accuracy
• Spatial and temporal resolution
• The use of atmospheric transfer models for the conversion from concentration to emission rate
• Emission source localization and attribution
• Non-representative sampling
• Lack of accurate activity data
• Environmental conditions
• Presence of unaccounted for sources
• Presence of intermittent, potentially high-emitting sources
This section will aim to discuss these main sources of uncertainty and their associated core concepts,
as well as how to manage them.
The key goal of assessing uncertainty is to be aware of how it can impact confidence in measurement-
informed inventories. While it is possible to reduce some sources of uncertainty, many sources
cannot be mitigated, and others can be extremely cost-prohibitive. For example, performing more
frequent measurements can decrease uncertainty associated with temporal variations and
extrapolations, but there is a trade-off between reduced uncertainty and cost.
While the knowledge on accurately quantifying methane emissions uncertainty is continually evolving,
a best practice has yet to be established. However, identifying and understanding the factors that
influence measurement uncertainty aids in proactively implementing strategies to reduce uncertainty.
5.7.1. Technology Performance Uncertainty
Technology uncertainty for CH4 detection and quantification considers errors associated with the
method or instrument and its intended use. Making an informed decision about the most suitable
technology is crucial for obtaining accurate and reliable CH4 data and minimizing uncertainty.
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Table 5 provides a summary of the main drivers of uncertainty in CH4 measurement technologies
along with potential considerations to mitigate each source.
Table 5. Overview of sources of uncertainty from CH4 emissions measurement technologies
Uncertainty Source
Uncertainty Consideration
Emission rate random error and systematic bias
The emission rate reported by measurement
technology can be a large source of uncertainty.
While some technologies provide an emission
rate via direct measurement of methane flow
rate (Hi-Flow samplers) some use concentration
measurements in conjunction with atmospheric
transfer models. Atmospheric transfer models
rely on multiple data streams and algorithms
which, while commonly accepted, could
introduce systematic bias.
Quantification error and bias can be
established through controlled release testing.
Known emission rates are blinded from the
tested technology which then must report
quantified emission rates. This can establish
an understanding of the relationship between
quantification error and emission rate.
Methane quantification error of measurement
technologies is becoming increasingly
published.
Probability of Detection
Probability of detection is the probability a
methane measurement technology can detect
an emission based on various factors like
emission rate, wind speed and direction,
distance of measurement technology to
emission source, etc. While all these variables
are important, probability of detection is most
often associated with emission rate: given
standard conditions, what emission rate will be
detected 90% of the time. Probability of
detection has a bearing on uncertainty in that it
defines the emissions which are too small to be
consistently detected by the methane
measurement technology.
The probability of detection of well-known
methane measurement technology classes
(aerial, handheld solutions, satellites, etc.) has
become increasingly public and accessible
over the last 2-3 years. Conducting controlled
release testing is not necessary, instead,
controlled release testing (see section 6.3) of
the technology in question, or, a similar
technology, should be consulted to form an
understanding of the emission sizes which
could be missed due to the technology’s
probability of detection.
Spatial Resolution
Different measurement technologies will “see”
emissions differently depending on their spatial
resolution. Spatial resolution is typically
described as either site-level, equipment-level,
or component-level. For example, a technology
which has site-level resolution (a satellite) will
“see” all emissions present at a site as one
single emission, whereas a technology with a
An understanding of the spatial resolution of
the technology can be established through
testing, or conversation with the technology
vendor. Incorporating measurements of
differing spatial resolution in a measurement
campaign can help reduce overall uncertainty.
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component-level resolution (handheld
solutions) would “see” the individual emissions
which make up the single site-level emission
“seen” by the satellite. While neither
measurement is inherently wrong, they can
differ. Component-level emissions can often be
better attributed and localized.
Environmental Conditions
The performance of all methane measurement
technologies can be impacted by environmental
conditions. The impact of environmental
conditions varies based on the technology and
its relationship to the given technology. For
example, aerial flyovers can struggle to provide
accurate measurements if there is thick cloud
cover or snow on the ground (in the case of
LiDAR surveys). Another example is that
continuous monitoring solutions require air flow
to move the methane plume across the sensor
for accurate readings.
An awareness of the technologies operational
windows is important. Often, these operational
windows are already well established by the
technology vendor companies so deferring to
them on work practice is recommended.
5.7.2. Technology Performance Uncertainty Mitigation Strategies
Operators should carefully consider the specific requirements of the application and the
characteristics of the monitoring environment when selecting CH4 measurement and detection
technologies. Validation against established methods and calibration are key practices to reduce
uncertainties associated with technology selection. Strategies to reduce uncertainty include:
• Technology Selection Based on Comprehensive Evaluation and Testing: Methane
measurement technology testing results have increasingly become publicly available as the
methane detection industry moves towards adoption of greater transparency. For example,
testing often establishes minimum detection limits and probability of detection (PoD).
Leveraging these existing results to select equipment with appropriate capabilities and
reproducible performance can help reduce performance uncertainty.ix
• Calibration: Calibrate sensors regularly using traceable standards.
• Use of Technologies with Appropriate Spatial Resolution: Where possible, deploy
technologies with varying spatial resolution concurrently to cross-check and validate
measurements, enhancing the reliability of the data.x
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• Data Post-Processing and Corrections: Implement post-processing algorithms and
corrections to compensate for known biases and uncertainties associated with the selected
technology.xi
• Regular Maintenance: Ensure regular maintenance of the selected technology to preserve its
accuracy over time.
5.7.3. Sampling Strategy Uncertainty
Sampling strategy uncertainty for CH4 measurement occurs as a result of the sampling process as
well as the assumptions made when applying measurement duration to leak duration. Table 6
provides an overview of key aspects of uncertainty related to sampling strategy and ways to mitigate
them.
Table 6. Overview of sources of uncertainty relating to sampling strategies
Uncertainty Source
Uncertainty Consideration
Representative Sampling
The choice of sample groups for measurement
may introduce uncertainty if the groupings do
not adequately represent the population
distribution.
Infrequent sampling can also introduce
uncertainty due to variations in CH4 emissions
with time, leading to incomplete or inaccurate
data. The Veritas Source-Level Measurement
and Reconciliation Protocol notes that
increasing the frequency of measurements aids
in estimating the typical duration and frequency
of emissions sources, ultimately diminishing the
uncertainty in annual emissions estimates.xii
Consider operational categories that represent
natural groupings of assets (e.g., asset type,
industrial vs. residential districts) and similar
emissions characteristics (e.g., pipeline
vintage or material). Randomly select sample
groups from each category to ensure an
adequate population representation. It is also
important to determine the appropriate
frequency for emissions measurements.
Sources that contribute more to the emissions
inventory (high materiality) or are believed to be
more intermittent in nature, may receive more
frequent surveys. Methods may be altered in
subsequent years to coincide with changes in
materiality assessments or may be updated
once the expected emissions distribution and
its source breakdown is better understood.
Consider continuous monitoring for real-time
data where applicable or practical (for
midstream and downstream operations,
continuous aboveground monitoring is unlikely
to be practical on buried pipelines or
geographically dispersed small assets but may
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provide valuable information on leaks from
larger aboveground facilities that are part of
those systems, such as compressor stations).
Measurement Duration
Measurement duration refers to the total time a
potential emission source is measured and
considered a single data point when
constructing a measurement informed
inventory. For example, some aerial methods
perform back-to-back flyovers (often over 1 or 2
days) to determine which emissions detected
during the first flyover are intermittent in nature.
These back-to-back flyovers are considered a
single measurement, and their nature mitigates
uncertainty. Another example is continuous
monitoring solutions who collect measurements
on a minute-to-minute or even sometimes
second-to-second timescale.
While ensuring longer measurement duration
will reduce uncertainty, it can be difficult in
practice to assure this across an entire
measurement campaign. It is recommended to
deploy technology with longer measurement
duration (i.e., continuous monitoring) on high
materiality sources (those that contribute a
large amount to an emissions inventory).
Estimated Emissions Durations
Many measurement campaigns obtain
“snapshot in time” measurements of emissions.
A crucial consideration is the assumptions
around how long these “snapshot” emission
measurements last. For example, if a
measurement campaign based on aerial flyovers
flags an emission during a screening but not
during the previous screening, do we assume
the duration existed the whole time between
screenings? Half the time between screenings?
Note, some regulations do have methodologies
in place for emissions duration calculations.
This uncertainty cannot be mitigated with
“snapshot in time” measurements (it will
always exist). It is advisable to simply be aware
of how emissions duration estimates are
calculated and if these calculations tend to
lead to over or under-estimations.
5.7.4. Sampling Strategy Uncertainty Mitigation Strategies
It's advisable to tailor the sampling strategy to the specific goals of the measurement program.
Mitigating uncertainty can be achieved through increased sample size and survey frequency, but
program cost and diminishing returns must be considered. Some strategies to mitigate uncertainty
associated with sampling strategy include:
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• Increased Sampling: Increase sampling to improve accuracy and precision, reduce sampling
bias, and provide more representative data.
• Site Stratification: Conduct a detailed site stratification to identify emission sources and
variability and identify representative sampling locations.xiii
• Continuous Monitoring: Implement continuous or semi-continuous monitoring systems
where applicable or practical to capture short-term events and provide a more comprehensive
dataset.xiv For midstream and downstream operations, continuous aboveground monitoring is
unlikely to be practical on buried pipelines or geographically dispersed small assets but may be
valuable for aboveground facilities such as compressor stations.
5.7.5. Extrapolation Uncertainty (temporal and spatial)
Spatial and temporal extrapolation uncertainty in CH4 detection and quantification arises from the
challenges of extending localized measurements to broader geographic areas and longer time
periods.
Table 7 provides an overview of key aspects of extrapolation uncertainty and potential mitigation
strategies.
Table 7. Overview of sources of uncertainty relating to extrapolation of CH4 emissions measurement data when developing inventories
Uncertainty Source
Uncertainty Considerations
Spatial Extrapolation
Extrapolating measurements from a
representative sample to a larger population
may introduce uncertainties due to spatial
heterogeneity.
Conduct systematic spatial sampling across
representative locations to capture variability.
Employ spatial modeling techniques such as
kriging or geostatistics to interpolate
measurements.
Use remote sensing data to enhance spatial
coverage and resolution.
Temporal Extrapolation
Extrapolating measurements performed over
short timeframes to the entire emissions
reporting period (one year) may introduce
uncertainty due to temporal variations, trends,
and seasonality.
Leverage probabilistic modelling to validate
temporal extrapolation based on the ergodic
hypothesis. As a simplified definition, the
ergodic hypothesis states that over time, a
system will explore all its possible “states” (in
this case, emissions behavior), with the time
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spent in each state reflecting its probability of
occurrence.
Consider increasing the frequency of
measurements to better account for temporal
variability and trends.
Consider deploying continuous monitoring
systems for detailed temporal assessments.
5.7.6. Extrapolation Uncertainty (temporal and spatial) Mitigation Strategies
It is important to acknowledge the complexities of spatial and temporal extrapolation and to adopt a
multi-faceted approach that combines various data sources, models, and methodologies. Regular
validation against ground-truth data is crucial for assessing the reliability and accuracy of
extrapolation methods. Mitigation strategies include:
• Integrated Monitoring Systems: Integrate data from multiple “scales” of measurement
(bottom-up measurements, and top-down measurements), to improve the spatial
representation of CH4 concentrations.xv
• Satellite-Based Observations: Where applicable, operators can utilize satellite observations
to minimize the need for spatial extrapolation, providing wide coverage and identifying spatial
patterns.xvi
• Machine Learning Models: Apply machine learning models trained on comprehensive
datasets to improve the accuracy of spatial and temporal extrapolation.xvii
• Inverse Modeling Techniques: Employ inverse modeling techniques that optimize emission
estimates based on observed concentrations, providing insights into spatial and temporal
patterns.xviii
• Data Assimilation Methods: Use data assimilation methods that integrate measurement data
with model simulations to improve the representation of spatial and temporal variations over
time as more data is acquired.xix
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6. Methane Detection and Measurement Technologies
6.1. Introduction
Natural gas transmission, storage, and distribution face unique challenges in CH4 detection due to a
large number of geographically dispersed assets, complex distribution pipeline networks, urban
operating areas, and small-sized leaks that can be challenging to detect with existing technologies.
When considering the performance of an emissions measurement technology, it is important to
consider both the technology itself and the methodologies used. Technologies refer to the hardware,
including deployment platforms and sensors, while methods refer to the combination of these
technologies with analytics and deployment practices.xx In particular, understanding these methods
and how they might work in collaboration within an overall program is critical when evaluating
performance.
A broad range of commercial CH4 detection or detection and quantification technologies exist which
can be utilized by operators to detect, locate, and quantify emissions. Technology selection requires
careful consideration of accuracy, efficiency, safety, and resourcing. It is important to understand if
and how a technology has been tested to verify its performance and specifications for effective use
and regulatory compliance.
Effective emissions management is not limited to technology selection; Considerable innovation has
occurred around deployment practices: thinking about how, when, where, and whether to deploy
different types of technologies, alone and in combination with complementary solutions. The use of
diverse sources of data, including operational, parametric and measurement, as well as
understanding which sources are best measured or best calculated can inform a more accurate
emissions inventory.
In this section, we will provide an overview of available technologies and discuss technology selection
considerations, sensing principles, deployment platforms, and controlled release testing. Technology
options will be identified that may be suitable for deployment on storage, transmission, and
distribution assets.
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6.2. Overview of Deployment Platforms and Sensing Principles
Classifying detection and measurement technologies helps to make sense of the 200+ commercially
available solutions, yet there are many possible ways to do so, and there is flexibility for a broad range
of approaches. This summary is meant to review the capabilities of a broad range of different solutions
and does not target any individual solution provider. It is meant to provide an overall picture of the
solutions available.
Historically, the legacy techniques for pipeline leak detections have been:
• Auditory, Visual, Olfactory (AVO) – the use of human senses to detect leaks, which can be done
from the ground or as an aircraft passenger (visual).
• Handheld – handheld leak detectors, Optical Gas Imaging (OGI) or laser detection.
• Continuous Monitoring – above or below ground mass balance detection, internal or external to
the pipeline.
Over the past decade there has been considerable innovation in the detection, localization, and
quantification of CH4. Innovation has accelerated in many areas, including deployment platforms,
sensors, testing procedures, work practices, and analytics. A large and growing number of advanced
methods now exist, including a range of point, active, and passive sensors deployed on handheld
instruments, aircraft, drones, vehicles, satellites, and stationary systems.
Technologies are classified according to deployment mode and sensing principles. CH4 sensing
instruments can be deployed on a variety of platforms, offering different advantages and
disadvantages. CH4 sensing technologies can be mobile or stationary.
Deployment modes can be generally classified into the following categories: satellites, aircraft,
unmanned aerial vehicles, mobile ground labs, continuous monitoring, and handheld. Table 8
summarizes these deployment modes and their advantages and disadvantages.
Specific cost data is dependent on, individual contracts between operators, technology providers, site
specific parameters, frequency, work practices, asset density, and other factors, therefore specific
cost data is not included in the table below.
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Table 8. Overview of commercially available CH4 emissions detection technology deployment modes
Measurement Technology Deployment Modes
Advantages Disadvantages
Satellites
Remote sensing instruments on satellites are used to detect and measure concentrations of
CH4 in the Earth's atmosphere.
• Global coverage for monitoring emissions
on a large scale.
• Identification of emissions from various
sources.
• Large sources identified by satellite can be
used for reconciliation with ground-based
data.
• Lower spatial resolution compared to ground-
based methods.
• Limited ability to detect small leaks.
• Generally, the highest cost to deploy, data
may be available to purchase from new
satellite technology providers.
• Weather conditions such as wind and cloud
coverage can impact data collection.
Aircraft
Typically, small fixed-wing aircraft or helicopters. These systems are in widespread use in
numerous countries, especially for upstream and midstream operations.
• Rapid coverage of large areas.
• Ability to target specific sources or regions.
• Higher spatial resolution compared to
satellite-based methods.
• Flexibility in flight patterns and altitudes.
• Higher operational costs compared to some
ground-based technologies.
• Weather conditions may affect flight
feasibility.
• Limited continuous monitoring capabilities
compared to satellite-based systems.
Unmanned Aerial Vehicles (UAVs)
Fixed-wing and rotary-propelled UAVs are emerging for detecting CH4 emissions at short and
medium ranges.
• Quick coverage of expansive areas.
• Access to remote and challenging terrains.
• Reduced human risk in certain inspections
where terrain or other barriers prevent
direct access.
• Often cannot operate beyond visual line of
sight (BVLOS) - the UAV pilot must be able to
see the UAV.
• Subject to air space and regulatory restriction,
particularly in urban areas or close to airports.
• Weather conditions may impact effectiveness.
• May require skilled operators.
• travel time can be comparable to handheld
solutions as operators must travel to
monitored area via truck.
• Costs vary depending on the aerial extent of
coverage.
Mobile Ground Labs (MGLs)
Pickup trucks, vans, or cars equipped with a variety of sensors for detecting CH4 and
measuring local atmospheric conditions.
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• Typically, MGLs are highly sensitive
compared to aerial methods (can detect
smaller emissions).
• Flexibility for periodic inspections.
• Rapid response to changing conditions.
• Ability to cover large and remote areas.
• Provide an allowance for work practices
which see follow-up surveys immediately
performed if onboard analytics are available
and MGL operators are trained in handheld
surveys.
• Weather, as well as road conditions, can affect
performance.
• Remote access monitoring areas may be
inaccessible due to road access or height and
field of view.
• Expected significantly increased resource
requirements for ground follow-up surveys to
locate and verify leak presence and deploy
repairs.
• Dependence on personnel availability.
• Less spatial coverage than aerial methods
unless multiple passes of monitored area are
conducted.
Continuous Monitoring
These systems are stationary. Continuous systems are uniquely positioned to resolve
temporal variability in emissions. Can be internal or external (i.e. Pipelines)
• Near-immediate detection of leaks
depending on wind speed and direction
• Continuous monitoring provides real-time
data.
• Integration with alarm systems for quick
response.
• Limited to specific locations, may not cover
entire facilities.
• Requires regular maintenance and calibration.
• Above ground operations affected by weather
and environmental conditions.
• Below ground deployment requires installation
at time of pipeline installation.
Handheld
Portable systems that are held by an inspector. These technologies are mandated by
regulations and leak survey guidelines in certain jurisdictions and include combustible gas
detectors, optical gas imaging (OGI) technology, and other types of technology (e.g.,
handheld laser CH4 detectors).
• Quick identification of leaks by visualizing
infrared emissions.
• Can be very sensitive in the hands of
experienced operators.
• Pinpointing source locations.
• Compliance with regulatory requirements.
• Direct measurement of emissions, as
opposed to using plume dispersion
modelling to arrive at emissions.
• Weather conditions and distance limitations.
• Depending on the complexity of the area to be
monitored, can have a low spatial coverage
(operators may not have access to sufficiently
survey all equipment).
• Can be time and resource consuming to do
walking surveys with handheld technology for
geographically extensive assets.
• Can be an affordable option to purchase,
however, deployment costs are dependent on
the manpower and resources required and the
extent of coverage.
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To add perspective, images of the data products provided by each of the six deployment methods
described above are shown below (Figure 4).
Figure 4. Visual representation of deployment platforms
Satellites (bottom right) can cover regional to global scales but may be limited in spatial resolution to
pinpoint localized sources or points of emissions. Aircrafts and drones (bottom middle and bottom
left) are not able to cover the same large areas as satellites but can more accurately target specific
regions or facilities. MGL (top right) coverage is dependent on road access but can be nimble and
adapt to changing conditions. In addition, while MGLs may be able to cover similar areas as aircraft
and drones, they may not be as time efficient. Continuous monitoring (top middle) is location specific
and will require multiple sensors depending on the size of the facility but allow for faster detection and
response to leaks. Handheld (top left) is effective for identifying emissions from specific sources and
components but is limited by walking speeds.
Beyond deployment platforms, there are also different sensor types that are mounted onto different
deployment platforms. Sensing principles can be classified into three general categories: active
remote imaging, passive remote imaging, and point sensing. The technologies, advantages, and
disadvantages are described in Table 9.
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Table 9. Overview of the sensing principles of commercially available CH4 emissions detection and measurement technology
Sensing Modes
Advantages Disadvantages
Active Imaging (Remote sensing)
Active imaging systems generate source(s) of light that traverse CH4 plumes, reflects off a remote
surface, and returns to a detector. Changes in the reflected light are used to infer CH4
concentrations along the path. A common example is Light Detection and Ranging (LiDAR)xxi.
• Direct interaction with the CH4 plume is not
required.
• More sensitive than passive imaging.
• Strong source attribution performance has
been demonstrated
• Targets individual sites instead of sweeping
coverage of the entire landscape (slower than
passive imaging).
• Follow up is required to localize and confirm
emission sources.
Passive Imaging (Remote sensing)
Passive imaging systems use reflected sunlight to measure CH4 concentration in the atmosphere.
They are used in all types of platforms, ranging from OGI cameras to satellite imagery.
• Technologies which use passive imaging
cover large areas quickly.
• Focus on large emitters.
• Site access is not required.
• Flexibility in flight patterns and altitudes.
• Follow up is required to localize and confirm
emission sources.
• Use is weather dependent and relies on the
presence of sunlight.
• Less sensitive – optimally suited for
identifying large emitters quickly.
Point Sensing
Point sensing involves directly measuring CH4 mixing ratios (the proportion of CH4 molecules in a
mixture of gases) in the atmosphere, which requires the sensor to be positioned in a plume to
discern anomalies above the background. Point sensors range from simple solid-state metal oxide
detectors to complex cavity ringdown spectrometers (CRDS) and gas chromatographs. Point
sensors can be deployed on any platform that passes through CH4 plumes or has CH4 plumes that
pass over the sensor. Hi-Flow sensors and Mobile Ground Labs are examples of point sensors.
• Most sensitive- can detect CH4 on a ppm or
ppb scale.
• Can be deployed on a variety of mobile and
stationary platforms.
• Direct contact with the CH4 plume is
required.
• Multiple passes through the plume are
needed for quantification.
• Slower than imaging technologies.
The deployment platforms and sensing principles outlined above can be combined in several ways.
For example, there are commercial aircraft-based technologies which operate using passive imagery,
active imagery, and point sensing. Each of these technologies perform differently to one another and
may be better suited for different applications.
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6.3. Controlled Release Testing
Controlled release testing is the process of testing the performance of a CH4 detection technology
against known release rates. Controlled release testing is used to validate claims about technology
performance, develop probability of detection curves, determine minimum detection limits, and
understand uncertainty/error bounds on individual measurements.
In controlled release tests, participants deploy technologies in a controlled release environment,
where there are dedicated release points, each capable of being turned on and off remotely, and with
adjustable release rates from each release point. Release points and rates are generally blind to
testing participants. Participants attempt to discern the presence of releases, the location of releases,
and release rates. After testing, participants submit their results, which are compared against the
actual releases, and performance metrics are developed.
The Methane Emissions Technology Evaluation Center (METEC) is the world’s leading testing facility
for CH4 sensing technologies. It is located at Colorado State University in Fort Collins, Colorado.
METEC was designed specifically as an academic research and testing facility for testing leak
detection and quantification methods in an upstream oil and gas context. The facility includes
aboveground oil and gas infrastructure, and buried pipelines and right-of-ways, to allow for testing of
technologies for a wide array of natural gas applications. See Section 6.5 for technology specific
results of controlled release testing.
In the absence of controlled release testing results, performance claims from a technology provider
may be challenging to verify. Technology performance and fit-for-purpose are critical considerations
when developing sampling plans and making technology selections. Controlled release testing results
may enable a company to decide whether a particular technology is suitable for use on their assets,
i.e. whether the instruments are sufficiently sensitive to capture the expected emissions from their
sites, and if it will provide useful and actionable information.
6.4. Technology Selection Considerations
Selecting CH4 detection technology for downstream operations requires careful consideration for
efficiency, safety, and effectiveness. When considering safety, regulatory compliance and the safety
of all stakeholders should be considered. The efficiency of the technology can include several factors
such as cost and scalability over the life cycle of the assets. When assessing your assets, the
effectiveness of technology to capture an accurate representative of your emissions profile can vary
with respect to leak size, aerial extent, and frequency of measurements.
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Table 10 outlines 14 considerations, grouped by color to indicate the following categories:
Table 10. Overview of technology selection considerations
Performance Fit for Purpose
Consideration Overview
Source and Facility Type: Consider the suitability to the specific sources you are trying to
detect or measure CH4 emissions from (Asset, Facility, and Source)
Need for Follow-up
Investigation
Consider the requirements for ground follow-up surveys to locate
and verify leak presence and deploy repairs
Sensitivity and Detection
Range:
Consider the technology's sensitivity to detect varying
concentrations of CH4 and leaks sizes.
Spatial Coverage: Consider the technology's capability to cover large areas, specific
zones, or critical points.
Temporal Coverage: Consider the frequency and duration over which measurements or
observations of CH4 concentrations will be made and data will be
collected.
Accuracy and Precision: Consider whether the technology has undergone controlled release
testing by an independent party to validate performance
specifications, determine minimum detection limits, and
understand uncertainty.
Durability in Variable
Environments:
Consider how the selected technology can withstand the varying
environmental and operational conditions common to the
geographic areas it will be deployed in.
Response Time: Understand the response time of the technology to provide leak
reports to the operator, particularly in the context of safety and
mitigating leak hazards quickly.
Safety Features: Review safety features, such as remote monitoring capabilities to
reduce human exposure to potential hazards.
Regulatory Compliance: Ensure that the selected technology complies with industry-
specific regulations and standards governing CH4 emissions.
Mobility and Flexibility: Consider whether the technology offers mobility for on-the-go
inspections (is the technology portable), especially in large facilities
or remote field locations.
Data Logging and
Reporting:
Consider the data logging, storage, and reporting capabilities of the
technology to understand what outputs will be obtained and how
they can be utilized.
Training and Ease of Use: If the technology is used by company employees, consider the
training requirements for operating and maintaining the technology.
Lifecycle Costs: Consider the overall life-cycle costs associated with the
technology, including equipment purchase, installation,
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maintenance, and potential future upgrades. Consideration should
also be given to resourcing requirements for ground follow-up to
locate and repair leaks.
Scalability: Consider whether the technology is scalable to accommodate
changes in facility size, infrastructure expansions, or modifications.
6.5. Technology for Storage, Transmission, and Distribution
Methane detection technology can be deployed on various platforms to monitor storage, distribution,
and transmission pipelines. The choice of deployment platform depends on factors such as the scale
of the pipeline network, accessibility, and monitoring requirements.
Combining multiple methods can provide a comprehensive approach to managing and mitigating CH4
emissions. Advances in technology continue to improve the accuracy, efficiency, and accessibility of
CH4 detection tools, and the methodologies to effectively incorporate the data captured. It was
recommended in several expert interviews conducted by Highwood Emissions Management that
combining different technology types will result in more leak detection events than any one
technology alonexxii.
Appendix 11.1 details the technology and characteristics suitable for storage, transmission, and
distribution. Not all technologies are applicable for all assets within each segment.
Due to the unique characteristics of transmission and distribution, certain technologies have
limitations based on current controlled release testing detection limits or are still in the early stages of
development and have not been implemented outside of a test environment.
In general, distribution systems have smaller and more leak events than transmission, requiring
technologies with lower minimum detection limits. Distribution also has below ground equipment with
added complications of urban infrastructure and variability in surface permeability.
Most methane emissions from transmission systems come from compressor stations, which have
unique complexities. For example, uncombusted methane (i.e., “slip”) is emitted in compressor
exhaust that may introduce noise and obfuscate the ability of screening technologies to discern leaks.
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7. 2022 EGI Fugitive Emissions Inventory Analysis
7.1. Introduction
This section provides an overview of EGI’s current approaches to quantifying and reporting fugitive
emissions.
First, there is a discussion of EGI’s 2022 fugitive emissions inventory including:
• Total fugitive emissions and year-over-year trends.
• Segment source category materiality assessment, including identification of components
contributing most to total emissions.
• Commentary on higher emitting sites with respect to station size and contribution.
Second, EGI’s current calculation methods are described followed by the leak detection and repair
practices, broken out by storage and transmission (STO) and distribution (DO).
7.2. Overview of STO and DO Reported Emissions
The fugitive emissions inventory is shown in tCO2e, or tonnes of CO2 equivalent and includes CO2 and
CH4 emissions. This tCO2e value for CH4 is calculated by multiplying the tonnes of CH4 emissions by
the Global Warming Potential (GWP) of CH4.
As noted in Section 4.1, GWP quantifies the warming impact of a particular greenhouse gas in terms of
its ability to absorb and retain heat in the atmosphere compared to CO2. EGI uses a GWP of 28 for CH4
based on the federal and provincial reporting programs' requirements (EGI changed from a 25 in 2021
to 28 in 2022 due to a regulatory requirement). This change only impacts the proportionate CH4
contribution to total CO2e fugitive emissions when converting from tonnes of CH4 to tCO2e (Table 11).
Table 11. Sample calculation to show the GWP change impact when converting tonnes of CH4 to tonnes of CO2e
GWP 25 28
CH4 (t) 100 100
CH4 (tCO2e) 2,500 2,800
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The total fugitive emissions for EGI from 2020-2022 are broken out by segment (Figure 5). Table 12
provides additional information, including the fugitive CH4 volumes in standard cubic meters (scm),
the relative contributions of each segment, and the aggregated year-over-year emissions.
Figure 5. EGI year-over-year fugitive CH4 emissions from 2020-2022
Year-over-year, the total volume of fugitive emissions decreased by 23% between 2021 and 2022, from
445,000 tCO2e to 344,000 tCO2e.
From 2021 to 2022, the STO contribution increased from 6% to 16%, while DO contribution decreased
from 94% to 84% of total fugitive emissions (Table 12). The increase in STO is a result of higher fugitive
detection as a result of LDAR surveys. The decrease in DO emissions can be partially attributed to the
identification and elimination of a double counting error from the DO equipment inventory, resulting in
a net overall reduction in reported fugitive emissions.
Between 2021 and 2022, there was a 76% increase in reported STO fugitive emissions volumes (scm)
attributed to an increase in the occurrence and volumes of leaks (detected through leak surveys). The
increase of the fugitive emission mass (tCO2e) is proportionately higher (113%) due to a regulatory
required increase in the CH4 GWP, from 25 to 28, between 2021 and 2022. Since most STO fugitive
emissions are obtained through direct measurements (3x/year), annual fluctuations in reported
emissions reflecting the reporting year's specific operating conditions are expected. As measurement
of emissions replaces the use of generic emission factors, the accuracy of reported emissions should
increase and total emissions, over time, can be expected to decrease because of continuous,
targeted repairs.
26 27
57
405 418
288
-
50
100
150
200
250
300
350
400
450
2020 2021 2022Fugitive Emissions (103tCO2e)STO DO
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There was a net decrease in reported DO fugitive emission volumes (scm) of 40% between 2021 and
2022. Due to the regulatory required increase GWP noted above, the overall decrease in
corresponding fugitive emission mass in tonnes of CO2 equivalent (tCO2e) was only 31%. Within DO,
there was an increase in fugitives attributed to third party damage events between 2021 and 2022.
However, due to an alignment of customer meter counts in 2022, a double counting error was
identified within the Legacy EGI count of commercial customer meter sets. This error was resolved,
resulting in a reduction of emissions for customer meter sets from approximately 231,000 tCO2e to
approximately 129,0000 tCO2e as a result of the decreased activity count.
Table 12. Contributions of STO and DO to the reported fugitive emissions inventory in 2020, 2021, and 2022
Total Emissions by Segment 2020 2021 2022
STO
Volume of fugitive CH4 [103 scm] 1,653 1,653 2,913
Fugitive emissions [103 tCO2e] 26 27 57
Contribution of STO to total tCO2e fugitives [%] 6% 6% 16%
DO
Volume of fugitive CH4 [103 scm] 25,612 26,351 15,933
Fugitive emissions [103 tCO2e] 405 418 288
Contribution of DO to total tCO2e fugitives [%] 94% 94% 84%
Totals
DO + STO [103 scm] 27,265 28,004 18,846
DO + STO [103 tCO2e] 432 445 344
7.3. Emissions from Transmission and Storage
This section provides a detailed breakdown of fugitive emissions by source category for EGI’s STO
segment, including:
• Compressor station equipment leaks
• Storage wells
• Other station equipment leaks (receipt/sales meter station, valve stations, and transmission
farm taps)
• Oil batteries
• Pipeline leaks (protected and unprotected steel)
• Storage gathering pipelines
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Table 13 presents STO fugitive emissions in tonnes of CO2 equivalent, by source.
Table 13. 2022 STO fugitive emissions by source
STO Source Category
2022 Fugitive Emissions
[tCO2e]
Contribution
(%)
Compressor Station Equipment
Leaks 35,308 62%
Storage Wells 8,677 15%
Other Station Equipment Leaks 8,240 15%
Receipt-sales Meter Station 6,182 11%
Valve Station 2,047 4%
Transmission Farm Tap 11 0.02%
Oil Batteries 4,328 8%
Pipeline Leaks 53 0.09%
Protected Steel 51 0.09%
Unprotected Steel 2 0.003%
Storage Gathering Pipelines 15 0.03%
Total 56,621 100%
The top 3 source categories account for more than 90% of STO fugitive emissions. These are
compressor station equipment leaks (62%), storage wells (15%) and other station equipment leaks
(15%).
A site-level breakdown of compressor station equipment leaks in 2022 (Figure 6) shows that Dawn
Compressor Station is the highest leaking compressor station (10,393 tCO2e), equivalent to the
emissions of the next three largest sites combined. Dawn Compressor Station is one of 24 stations but
accounts for 30% of overall emissions, thus exhibiting the ‘heavy tail’ commonly observed in CH4
emissions distributions.
The comparatively higher emissions at the Dawn Compressor Station can be explained by the fact that
it is one of the largest integrated natural gas storage facilities in North America with eight
compressors. Comparatively Parkway, the second largest contributor, has only two compressors.
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Figure 6. STO equipment leak emissions breakdown per location (tCO2e)
A breakdown of leak counts by component type at compressor stations reveals that more than half of
all leaks occur at connectors and an additional third at valves (Figure 7). Only a small number of leaks
occur on other component types.
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Figure 7. Number of leaks per component for STO compressor leaks
Figure 8. Volume of leaks per component for STO compressor leaks
Based on total volumes (Figure 8), the leaks from valves and open-ended lines, while less frequent,
are larger on average than the more frequent leaks from connectors. Connectors, which contributed
54% of the total number of leaks, only contributed 23% of the total volume of leaks. Valves, which
represent 34% of total number of leaks, contributed 60% of the total leak volumes. Pressure Relief
Valves and Regulators, which contributed a combined 10% of the number of leaks, contributed a
negligible amount to the total volume. Open-ended lines, which contributed only 2% of the total
number of leaks, contributed 16% of the volume.
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7.4. Emissions from Distribution
This section provides a detailed breakdown of fugitive emissions by source category for EGI’s DO
segment, including:
• Customer meter sets (industrial/commercial, residential)
• Leaking buried pipe – service (plastic, protected steel, unprotected steel)
• Distribution stations (gate, district)
• Damage events (services, mains)
• Farm taps
• Leaking buried pipe – mains (plastic, protected steel, unprotected steel)
Table 14 below shows the 2022 Distribution fugitive emissions by source.
Table 14. 2022 DO fugitive emissions by source
DO Source Category
2022 Fugitive Emissions
[tCO2e]
Contribution
(%)
Customer Meter Sets 128,906 45%
Industrial/Commercial 69,422 24%
Residential 59,484 21%
Leaking Buried Pipe – Services 52,270 18%
Plastic 12,384 4%
Protected steel 5,704 2%
Unprotected steel 34,182 12%
Station Leaks 42,539 15%
Gate 24,906 9%
District 17,633 6%
Damage Events 26,349 9%
Services 15,704 5%
Mains 10,644 4%
Farm Taps 25,598 9%
Leaking Buried Pipe – Mains 12,015 4%
Plastic 750 0.26%
Protected steel 11,157 4%
Unprotected steel 108 0.04%
Total 287,677 100%
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The top three sources account for 78% of total fugitive emissions. These are customer meter sets
(45%), leaking service pipelines (18%) and station leaks (15%). Within customer meter sets, each of
the two sub-categories represent a larger contribution than any other single category. Leaking buried
unprotected steel pipe is also a notable contributor as the third largest single sub-category.
Table 15 shows the breakdown of the contribution of commercial and residential customer meter sets
to fugitive emissions. Residential meter sets, which represent 96% of the asset population by meter
count, are responsible for 46% of meter set fugitive emissions. This is driven by the activity count of
over 3.6 million residential meters, and the comparatively lower generic emission factor. This is a
significant contributor to DO emissions and while the activity counts are relatively constant, the
generic emission factor being used may or may not accurately reflect the total emissions from this
source resulting in a high uncertainty in the reported emissions in this category. Without company-
specific emission factors based on measurement data to increase the accuracy of emissions, this will
continue to be a source category with high uncertainty.
Table 15. 2022 DO breakdown of customer meter sets by emissions and activity factor
Customer Meter Sets
Emissions
(tCO2e)
Emission %
Contribution Meter Count
% of
Activity
Count
tCO2e/
Leak
Commercial/Industrial 69,422 54% 167,924 4% 0.41
Residential 59,484 46% 3,678,571 96% 0.02
The second largest source category is services pipelines at 18%, with unprotected steel contributing
12% alone. As with the customer meter sets, the emissions are calculated by multiplying an activity
factor (total equivalent leak ratio) and a generic emission factor. Without company-specific emission
factors based on measurement data to increase the accuracy of emissions, this will also continue to
be a consistently large source category (will always be a materially large source based on activity, but
more accurate emission factors could increase or decrease materiality) with high uncertainty.
Developing company specific emission factors will increase the accuracy of emissions and be more
reflective of EGI’s emissions.
7.5. Calculation Methods
This section provides an overview of the methodologies used by EGI for calculating fugitive emissions
from STO and DO assets.
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7.5.1. STO Calculations
Table 16 below shows the inventory calculation methods associated with each fugitive source
category for STO
Table 16. STO fugitive source categories and associated fugitive emissions inventory calculation methods
STO Fugitive Source Category
Percent
Contribution 2022 Calculation Method
Compressor station equipment leaks 62% Measurement
Storage wells 15% Generic EF
Other station equipment leaks 15%
Receipt-sales meter station 11% Measurement
Valve station 4% Generic EF
Transmission farm tap 0.02% Generic EF
Oil batteries 8% Generic EF
Pipeline leaks 0.1%
Protected steel 0.1% Generic EF
Unprotected steel 0% Generic EF
Storage gathering pipelines 0.1% Generic EF
EGI’s STO fugitive emissions inventory is calculated using a combination of measurement and generic
emission factors. Additional inputs into the calculations include annual equipment operating hours
(used to extrapolate emission rates to the total emissions estimate for the year) and gas composition
values (which represent the ratio of CH4 within the total natural gas). Activity factors such as
component and equipment counts are maintained and updated annually to ensure the calculation
basis is current, as these counts impact the emissions calculations.
73 % of EGI’s STO fugitive inventory is calculated via direct measurement, where leak detection and
measurement surveys are performed, and the results are used to inform the final fugitive inventory.
The remaining 27% of STO’s fugitive inventory is calculated using generic emission factors (obtained
from industry standard guidance and publications, as per the Ontario Guideline), applied to all
components within each population of sources (the activity factor). Calculating fugitive emissions
using this methodology does not require that leak surveys are conducted to determine the number of
emitting components; rather, the same emission factor is applied to all components, regardless of if
they are leaking or not.
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Compressor Station Equipment Leaks
Fugitive emissions from compressor stations are calculated using direct measurement of leak rates
obtained during regulatory LDAR surveys. The total leak volume for a given year is aggregated by taking
the hourly leak rates from leak surveys and approximating the duration using the methodology
provided in the Ontario GHG Guidelinexxiii.
Storage Wells Leaks
Storage well leaks are calculated utilizing a generic emission factor for storage wells (expressed in
tCH4/well/year), multiplied by the number of wells (the activity factor).
Other station equipment leaks
• Receipt-sales meter stations
Fugitive emissions from receipt-sales meter stations are calculated in the same manner as
compressor stations: utilizing direct measurement of leak rates from regulatory LDAR surveys. The
total leak volume for a given year is aggregated by taking the hourly leak rates from leak surveys and
approximating the duration using the methodology provided in the Ontario GHG Guideline.
• Valve stations
Valve station fugitive emissions are calculated by multiplying a generic emission factor (m3 natural
gas/year/station) by the total number of stations (the activity factor).
• Transmission farm taps
Transmission farm tap fugitive emissions are calculated by multiplying a generic emission factor (m3
natural gas/year/station) by the total number of farm taps (the activity factor).
Pipeline Leaks
Pipeline leaks in the transmission segment are reported by pipeline material: protected steel, and
unprotected steel. Pipeline fugitive emissions are calculated using a company specific total
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equivalent leak (TEL) ratio (calculated using company specific leak statistics) multiplied by a generic
emission leak rate (m3 natural gas/leak/year).
Storage Gathering Pipeline Leaks
Leaks from gathering lines are calculated utilizing a generic emission factor (tCH4/km pipeline/year)
multiplied by length of gathering lines (the activity factor).
DO Calculations
Table 17 below shows the inventory calculation methods associated with fugitive source categories
for DO.
Table 17. DO fugitive source categories and associated fugitive emissions inventory calculation methods
DO Fugitive Source Category
Percent
Contribution 2022 Calculation Method
Customer meter sets 45% Industrial/Commercial 24% Generic EF
Residential 21% Generic EF
Leaking buried pipe – services 18% Plastic 4% Generic EF
Protected steel 2% Generic EF
Unprotected steel 12% Generic EF
Above grade meter-regulating stations 15% Gate 9% Generic EF
District 6% Generic EF
Damage events 9% Services 5% Generic EF
Mains 4% Generic EF
Farm taps 9% Generic EF
Leaking buried pipe – mains 4% Plastic 0.3% Generic EF
Protected steel 4% Generic EF
Unprotected steel 0.04% Generic EF
Below grade meter-regulating stations 0.01% Generic EF
For all of EGI’s DO assets, fugitive emissions are calculated using the generic emission factor method
(see Table 8, Section 6.3). Emissions are calculated by multiplying activity factors (asset and
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component counts) with generic emission factors (obtained from industry standard guidance and
publications, as per the Ontario Guideline).5,6 This multiplication yields an emissions volume, reported
in m3 natural gas/year. To convert this to CH4 mass, the emissions volume is multiplied by the default
CH4 density (0.678 kg/m3), and annual hours of operation (8760 hours, unless otherwise specified), as
per Ontario GHG Guideline.
Customer Meter Sets
For commercial and residential meter sets, emissions are calculated by multiplying the number of
meter sets (the activity factor) by the associated emission factor. The meter set emission factor is
derived by multiplying generic component counts and generic component emission factors.
Leaking Buried Pipe- Services
For leaking buried service pipelines (including plastic, protected steel, unprotected steel, and copper
pipelines) emissions are calculated from the number of leaks based on the company specific total
equivalent leaks ratio (the activity factor) multiplied by a generic emission factor expressed in units of
m3 natural gas/leak/year.
Above grade meter-regulating stations
For above grade meter-regulating stations, including gate stations, district regulator stations, and
receipt/sales meter stations, emissions are calculated utilizing the number of stations (the activity
factor), multiplied by a station emission factor. The station emission factor is obtained by multiplying
the generic component counts by the generic emission factors for those components, expressed in
units of m3 natural gas/year/station.
Damage events
For damage events, including both mains and service lines, emissions are calculated utilizing the
number of events per year (the activity factor) multiplied by a generic emission factor, in units of m3
natural gas/event.
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Farm taps
For farm taps, emissions are calculated by multiplying the number of stations (the activity factor) by a
station emission factor. The station emission factor is the sum of the generic component counts
multiplied by the generic emission factors, expressed in units of m3 natural gas/year/station.
Leaking buried pipe – mains
For leaking buried main pipelines (including plastic, protected steel, and unprotected steel)
emissions are calculated utilizing the number of leaks based on the company specific total equivalent
leaks ratio (the activity factor) multiplied by a generic emission factor expressed in units of m3 natural
gas/leak/year.
Below grade meter-regulating stations
For below grade meter-regulating stations including those with inlet pressures of >300psig, 100-
300psig, and <100psig, the emissions are calculated utilizing the number of stations (the activity
factor), multiplied by a generic emission factor expressed in units of m3 natural gas/hour/station.
7.6. Uncertainty in EGI’s Inventory – Clearstone Study
In 2021, Clearstone Engineering Ltd. Conducted an analysis of the potential uncertainties associated
with the EGI’s 2020 reported fugitive emissions inventories. The uncertainties associated with fugitive
emissions are presented in Table 18. As the methodology by which EGI’s fugitive inventory is
calculated has not significantly changed since the Clearstone study was conducted, the uncertainties
reported in Table 18 are likely representative of the current inventory.
Table 18. Summary of the calculated uncertainties for the 2020 GHG inventory, as assessed by Clearstone Engineering in 2021
Segment Fugitive Uncertainty
Transmission 8.2%
Storage 3.1%
Distribution 117.6%
Sources of uncertainty which were considered within these calculations included uncertainties from
individual metered gas volumes, leak rates measured as part of leak detection and repair programs,
activity values and time counts, gas composition, and uncertainty assigned to the emission factors
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used in the inventory calculations. The study noted that individual emissions values quantified as part
of leak detection and repair studied were assigned an uncertainty of ±15%.
Note that EGI’s distribution fugitive emissions are calculated using generic emission factors and
activity counts (Table 6). All activity counts were assumed to have an associated uncertainty of 5% by
Clearstone, and the number of individual components is significantly higher in DO than in STO,
contributing to a higher associated uncertainty because the uncertainty implied in the generic
emission factor is applied to a large population. Leak Survey Practices
7.7. Leak Survey Practices
7.7.1. Background
Due to differing risk factors, operating conditions, and operational controls (such as construction and
maintenance specifications, and presence of pressure monitoring systems), leak survey requirements
differ significantly among different segments of the natural gas supply chain.
Gas utilities (i.e. distribution companies) must conduct regular surveys of their entire network to
ensure public safety as part of regulatory compliance. Studies have shown that leaks on distribution
systems are highly dependent on the age and material of pipes, and that the leaks that do occur in
these systems tend to be relatively smallxxiv. Detection and localization of these small leaks, for
eventual repair, is also a significant challenge, due the size and complexity of distribution networks,
and their location in urban areas, often buried under pavement.
Midstream operations, especially large, high-pressure, and high-volume transmission systems,
transport large volumes of natural gas, and present a more significant risk to people and environment
in the case of an incident and are therefore closely and continuously monitored for potential incidents
and process upsets. They are also built to a higher spec than smaller, lower pressure pipeline, as per
CSA Z662 standardxxv.
Detecting and repairing leaks significantly reduces emissions from gas transmission, storage, and
distribution systems.
In this section, an overview of EGI’s leak survey practices across transmission, storage, and
distribution assets is provided, including the technologies used and the coverage and frequency of
deployment. EGI conducts regular leak surveys on all assets to ensure safety, asset integrity, and
regulatory compliance.13 In some cases, information gathered as part of the leak survey program is
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used to estimate emissions for EGI’s reported inventory. For each of the segments, a discussion of
how results from leak detection campaigns are integrated into inventory calculations is provided.
Leak survey technologies are used to detect the presence of leaks. Technologies also exist that are
capable of both detection and quantification, which provide a measurement of the flow rate of the
detected leak. Detection-only technologies, which have been the industry standard for leak surveys,
may directly measure the concentration of CH4 gas in the air or indirectly infer the presence of a leak
through pressure changes, process upsets or audio, visual, olfactory (AVO) methods.
7.7.2. Transmission Leak Survey Practices
EGI’s transmission system consists of buried transmission pipelines and associated aboveground
infrastructure, including compressor stations and pigging stations.
Overview of current LDAR Practices
Transmission pipelines, due to their high operating pressures, large size, and high carrying capacity,
are monitored closely and consistently for potential leaks, using a variety of techniques and methods.
Current leak survey practices on EGI transmission pipelines detect the presence of leaks. Leak survey
practices on transmission compressor stations and meter/receipt stations use detection and
quantification technologies to additionally measure leak flow rates.
LDAR Overview
Below outlines the different technologies used in EGI’s transmission system.
• Visual inspection of pipeline right of ways
Visual right of way inspections are conducted as part of regulatory requirements. Weekly, a small
aircraft (airplane or helicopter) passes over the pipeline right of way as trained personnel check for any
visual signs of leaks or disturbances on the pipeline or immediate surrounding area. Indications of
potential leaks include dead vegetation, areas of melted snow, or visible encroachment or
disturbance. Visual inspections do not involve the use of any detection or quantification technologies.
• Foot patrol with handheld gas monitor
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In addition to the visual inspections on right of ways, EGI’s transmission pipeline system is surveyed
by foot, by trained personnel carrying handheld gas monitors, which are capable of sensing CH4
concentrations in the air immediately above the buried transmission pipeline. EGI’s handheld gas
monitors detect CH4 concentrations but do not quantify leak flow rates.
• Ground-based follow ups of visual inspections
If the visual inspections result in the identification of potential leaks, a ground-based follow up is
performed, using a handheld method (gas monitor or OGI camera). The purpose of the follow up is to
pinpoint the source of the leak for repair and emission mitigation.
• Satellite imagery for visual signs of impact
EGI annually reviews satellite and aerial imageryxxvi for any visual changes to the areas within their
transmission system. Potential signs of leaks include dead vegetation (which often appear as large
circles of dead vegetation, contrasted against otherwise healthy vegetation), melted snow (often
appearing as circles of melted snow), and visual encroachment.
• Smart pigging
Smart pigs are sent through the pipeline, which carry sensors which can measure any physical
changes or deformities in the internal structures of the pipeline. Smart pigs may be able to identify
weak areas or areas which are more prone to failure, which allow repairs to happen in advance of a
failure. EGI utilizes smart pigging within their transmission system.
• SCADA system monitoring
All pipelines within EGI’s transmission network are monitored continuously by a Supervisory Control
and Data Acquisition (SCADA) system, which can identify potential signs of a leak, including pressure
changes and vapor concentration changesxxvii. Both crude oil and natural gas transmission pipelines
are monitored 24/7/365 by SCADA.
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• Mass balance calculations
Mass balance calculations are performed multiple times per day, which calculate the volume of
natural gas flowing through the pipelines, at different locations within the pipeline system, to verify
that the volumes are not changing. Losses of flow rates from one point within the pipeline to another
would indicate the presence of a potential leak. These digital monitoring controls can localize
potential leak sources to between two points along the pipeline and can be used to inform and direct
more detailed follow up methods, which would be similar to the ground-based follow ups of visual
detections, as discussed above.
• OGI and hi-flow sampler (for compressor and meter/receipt stations only)
Compressor stations are surveyed for leaks as part of EGI’s obligations under the Ontario GHG
Reporting Program and the federal methane regulations, using an optical gas imagine camera (OGI).
Additionally, EGI quantifies the flow rate of each leak detected using a hi-flow sampler.
Coverage and Frequency Overview
EGI’s full transmission system is surveyed using flyovers on a weekly basis and ground-based
methods on an annual basis. Compressor stations, and meter/receipt stations are surveyed three
times per year using ground-based OGI, and quantification of leak rates is performed using hi-flow
sampling. This coverage and frequency are in line with the regulatory requirements.
Impacts of LDAR on Reported Inventory
Transmission pipeline fugitive emissions are calculated using the generic emission factor method as
per the 2022 CEPEI manual based on Total Equivalent Leaks (TEL). Results from leak surveys are not
included in emissions calculations since flow rates are not being measured.
Fugitive emissions from compressor stations and meter/receipt stations are calculated using the
measured emissions from the regulatory LDAR surveys. The total leak volume for a given reporting year
is aggregated by taking the hourly leak rates from the surveys and approximating the duration using the
methodology provided in the Ontario GHG Guidelinesxxviii.
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7.7.4. Storage Leak Survey Practices
EGI’s storage system consists of storage wells, compression systems, and other aboveground
infrastructure to support injecting and withdrawing natural gas from storage.
Overview of current LDAR Practices
Leak survey is performed at all storage facilities, including the LNG facility.
Current leak survey practices on EGI storage assets, including compressor stations and other
aboveground infrastructure, use detection and quantification technologies. Detection is performed
using optical gas imaging, and quantification of detected leaks is performed using hi-flow samplers.
LDAR Overview
Below outlines the different technologies used in EGI’s storage system.
• OGI and hi-flow sampler
Compressor stations and meter/receipt stations are surveyed for leaks as per regulatory
requirements, using OGI is for detection of leaks. Additionally, EGI performs hi-flow sampling to
quantify leak rate.
Coverage and Frequency Overview
Leak surveys are performed at all storage facilities three times per year, consistent with regulatory
requirements. Hi-flow quantifications are performed on all the OGI-detected leaks.
Impacts of LDAR on Reported Inventory
Like transmission leak survey practices, fugitive emissions from compressor stations and
meter/receipt stations are calculated using the measured emissions from the regulatory LDAR
surveys. The total leak volume for a given reporting year is aggregated by taking the hourly leak rates
from leak surveys and approximating the duration using the methodology provided in the Ontario GHG
Guidelinesxxix.
7.7.5. Distribution Leak Survey Practices
EGI’s distribution system consists of gas distribution pipelines (mains and service lines), customer
meter sets, above grade meter-regulating stations, and farm taps.
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Overview of current LDAR Practices
Gas distribution pipelines operate under low pressure and flow rates and are the smallest in diameter
of pipeline types. They are also the most prevalent type of gas pipeline with thousands of kms of
distribution mains and service lines under EGI’s operation. Current leak survey practices for EGI’s
distribution network involve detecting, classifying, and repairing leaks to ensure customer safety. The
current practice does not include measurement of leak flow rate.
LDAR Overview
The following technologies are used to perform leak surveys of EGI’s distribution system.
• Handheld ppm gas detector (sniffer)
Handheld ppm gas detectors are used to conduct walking surveys of distribution systems.
• Vehicle-mounted gas detector
Vehicle-mounted gas detectors are used to conduct surveys in rural areas. In addition, a vehicle-
mounted advanced mobile leak detection (AMLD) system, capable of detecting and quantifying leaks,
was piloted in 2023.
Coverage and Frequency Overview
Annual leak surveys are performed on a portion of distribution assets, covering about one-fifth of the
system yearly. Surveys are conducted on foot and by vehicle, using gas detectors, which detect CH4
concentration (ppm) in the air.
Leak surveys of pipelines and meter set assemblies are conducted every 1, 4, or 8 years depending on
the characteristics of the individual pipe that serves the customer meter (as per CSA Z662). Also, as
per the Electricity and Gas Inspection Act, statistical sampling and verification of gas meters occur to
monitor compliance with the Electricity and Gas Inspection Act (i.e., confirm measurement accuracy).
Any time a gas meter is part of this statistical sampling program, or if the sample group fails and the
full group of gas meters needs to be exchanged, a leak check and operational inspection are
performed on the meter set assembly by a licensed gas fitter. EGI field reps also look for leaks when
they do meter set exchanges for all assets above ground, upstream and downstream of the regulator
and meter.
Any customer calls for the smell of gas, fire, fumes, TSSA investigation, etc., triggers a complete leak
check and inspection of the meter set assembly by licensed gas fitters. Leaks are assigned a risk level
relative to their size.
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Impacts of LDAR on Reported Inventory
DO emissions are calculated using generic EFs. Since DO LDAR practices do not include measuring
leak flow rates, this information cannot be used to calculate emission factors. However, activity
information obtained during LDAR surveys, including leak counts and repairs, is used to calculate the
total equivalent leak ratio (activity factor). Currently, this activity factor is used to calculate emissions
for buried distribution pipelines, including both services and mains.
8. Technology Deployment Scenario Analysis
8.1. Introduction
The purpose of the scenario analysis is to evaluate different options for measuring fugitive emissions
from EGI’s transmission & storage, and distribution segments. EGI is seeking to develop a robust
fugitive emissions measurement plan (FEMP) to decrease uncertainty in reported fugitive emissions.
Technology performance, as well as other considerations such as cost, feasibility of implementation,
impacts on emissions uncertainty, and survey and travel time, must be evaluated to understand the
most suitable option to meet EGI’s goals. A holistic evaluation of possible options is intended to aid
EGI with developing a FEMP and identifying associated risks and opportunities.
To complete this holistic evaluation of different potential programs, a qualitative and quantitative
analysis was undertaken. Highwood conducted a quantitative analysis to estimate the time and
associated cost to complete surveys, potential emissions mitigation, number of detected leaks, and
measurement uncertainty of each scenario. For the qualitative analysis, industry research and
analyses were used to evaluate the primary sources of uncertainty impacting quantitative results,
opportunities and risks, and which scenarios offered the best performance, considering the
combination of all metrics evaluated.
The objectives of this scenario analysis are to provide an overview of different possible measurement
options and evaluate which may be the most suitable for EGI to reach their goals of more accurately
quantifying fugitive emissions and reducing uncertainty, in line with OEB commitments. In addition,
EGI aims to maximize potential emissions mitigation opportunities.
8.2. Background Information
For the scenario analysis, EGI's DO and STO segments were considered separately, and the latter was
evaluated qualitatively. Highwood focused its quantitative analysis on the DO segment due to its
larger contribution to overall fugitive emissions and the higher uncertainties associated with the
current emission calculation methods. The DO segment encompasses all the infrastructure that is
associated with downstream gas distribution, including buried main and service pipelines, meter-
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regulating stations, farm taps, and customer meter sets. The STO segment consists of transmission
systems and gas storage facilities, which include transmission pipelines, compressor stations, and
other infrastructure such as receipt stations, valve stations and farm taps.
The decision to exclude the STO segment from the quantitative analysis was driven by several factors.
First, the uncertainty of the EGI emissions inventory for the STO segment is significantly lower than the
DO segment, as demonstrated by the Clearstone analysis (section 7.6). Second, as reviewed in
section 7.2, the reported volumes of fugitive emissions for the company are primarily attributed to the
DO segment. Third, existing leak survey practices on the STO segment already include the detection
and quantification of fugitive emissions three times per year (section 7.7.3) for compressor stations
and receipt-sales meter stations, with even more frequent surveys expected as a result of upcoming
amendments to the Canadian methane regulations. Given these considerations, efforts were focused
on the DO segment. However, the STO segment still underwent a qualitative scenario analysis and is
discussed in the recommendation section (Section 9).
8.3. Methodology
8.3.1. Quantitative Analysis
FEMP Scenario Construction Methodology
FEMP scenarios for DO segment were developed through collaboration with EGI and were selected
based on a high-level technology overview which assessed potential technologies of interest for
deployment. This overview also considered technologies in use for other North American gas utilities,
as well as those technologies specifically identified in the EB-2022-0200 – 2024 Rebasing, partial
settlement agreement.
A note on terminology: A FEMP scenario considers measurement of leak flow rate which is not
required under an LDAR program. For the quantitative analysis we are required to assume that all
scenarios incorporate formal measurement of all detections, thus we refer to all scenarios as FEMP
scenarios.
When developing screening and survey (see glossary) frequency and coverage parameters for the
scenarios, EGI’s stated goal of accurately measuring fugitive emissions (i.e., reducing uncertainty in
the fugitive emissions inventory) was given the highest priority, and as such, all FEMP scenarios which
were selected are believed to have lower uncertainty compared to the currently deployed LDAR
program for DO as it contains no measurement (current practices described in section 7). This
lowered uncertainty stems from these options using measurements of EGI’s emissions (as opposed to
generic EFs), increased frequency of deployment, and increased coverage – all characteristics known
to decrease emissions uncertainty.
Satellites, aircraft (helicopters), vehicles and handheld technologies were evaluated to assess the
potential performance of each, considering uncertainty, technical feasibility of deployment, etc. Some
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scenarios use a combination of different methane detection and quantification technologies. These
scenarios aim to assess if there are tangible benefits to deploying multiple technologies, such as
improved detection capabilities, speed and coverage advantages, or survey efficiencies.
A full overview of the key inputs and assumptions associated with each of the explored FEMP
scenarios described below is available in the attached appendix. Components of the FEMP scenarios
which were considered include:
• Detection threshold of the methane detection/quantification technology.
• Frequency of surveys/screenings.
• Time to complete a survey/screening.
The following FEMP scenarios were explored in the quantitative and qualitative scenario analysis:
Handheld Every 7 Years FEMP Scenario
A FEMP Scenario that considers handheld surveys of all infrastructure every 7 years. While EGI
currently conducts leak surveys without measuring leak flow rates, the quantitative analysis
necessitates that we assume each detected emission is measured, hence the FEMP Scenario
terminology.
The current LDAR program is based on historic practices of surveying approximately 1/7th of the
infrastructure each year using handheld portable gas monitors on foot (in rural areas, operators drive
with gas monitors). Detected leaks are evaluated and assigned a relative risk level (safety), which is
how repairs are triggered. Due to the model's limitations, we modelled a scenario which sees the
entire infrastructure surveyed every 7 years. This modelling is based on the historic LDAR Program,
with EGI now surveying approximately 1/5th of the infrastructure each year (larger area surveyed per
year).
Handheld Every 3 Years FEMP Scenario
This scenario is identical to the “Handheld Every 7 Years” Scenario, only here the program sees a
survey of the entire system every 3 years (again, to represent a real-world scenario which sees 1/3rd of
the infrastructure surveyed each year).
Annual Full System Coverage FEMP Scenarios
A series of scenarios were explored in which the full system receives annual surveys with satellite,
aerial, vehicle, or handheld technology deployment. Each technology is considered separately within
these scenarios (scenarios do not consider technologies working in combination).
Twice per Year Full System Coverage FEMP Scenarios
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This FEMP scenario considers a semi-annual (twice per year) deployment of vehicle-mounted
technology. All assumptions and simulation inputs are consistent with the annual full system
coverage scenario.
Technology Combination FEMP Scenarios
A series of FEMP scenarios with a combination of methane detection and quantification technologies
was explored. These technology FEMP scenarios are:
• Multi Tech FEMP Scenario 1: Aerial 1x/year + Vehicle 1x/year + Handheld 1x/year
• Multi Tech FEMP Scenario 2: Aerial 1x/year + Vehicle 1x/year + Handheld every 3 years
• Multi Tech FEMP Scenario 3: Aerial 1x/year + Vehicle 1x/year
• Multi Tech FEMP Scenario 4: Vehicle 2x/year + handheld every 7 years
• Multi Tech FEMP Scenario 5: Vehicle 1x/year + handheld every 7 years
The same considerations are in effect for the technology combination scenarios as described above,
but now they are considered as working together. The primary purpose for the five combination FEMP
scenarios is to compare the mitigation potential and number of detected leaks between the scenarios
and understand how the inclusion (and frequency) of the handheld deployment affects the
performance of the FEMP.
Survey Time, Personnel and Survey Cost
An initial analysis outside LDAR-Sim was completed to estimate the total time required to complete
surveys.
Survey Time and Personnel
Survey time and personnel requirements were calculated based on pipeline length, method speed and
deployment windows. See the following assumptions:
• Method speed:
o Vehicle: 35 km/hr (280 km/day) considering average urban speed and method
performance.
o Handheld: 0.75 km/hr (6 km/day), informed by EGI.
o Aerial: 110 km/h (880 km/day), based on average Bridger Photonics speed when
deploying across the distribution sector. Aircraft would be a helicopter flying as low as
local regulations allow.
• Length surveyed:
o Vehicle: The entire length of pipelines. The vehicle method must intersect the plume.
So, they need to perform the surveys following the pipeline in a straight line. Each survey
considered 6 passes.
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o Handheld: The entire length of pipelines, based on the same logic as the vehicle
method. Each survey only includes 1 pass.
o Aerial: Only mains length. Bridger “sees” a grid, so an assumption is made that they can
“see” service lines in the grid.
• Deployment window
o All surveys had to be completed between April and October, which corresponds to
approximately 120 working days per year.
o Each personnel was considered to work 8 hours per day.
Survey cost
Cost for methane measurement technology deployment is extremely difficult to predict. Cost will
generally depend on the business model of the solution provider and indirect costs associated with
deployment, such as increased data management requirements, field personnel, and the need for
specialized software. The most common business models include:
• Upfront/capital costs
More common for handheld systems, continuous monitoring or any solution where the operator
must purchase equipment (rather than contracting to a solution provider).
• Recurring costs
o Cost per time: Most common approach for service providers because labour can be the
most expensive component of a survey (especially for ground-based methods that have
to travel/drive between locations). Daily rates lead to cost sensitivity due to variable
asset densities and facility size. Cost per hour or day is more common for handheld
methods.
o Ongoing subscription costs: Ongoing subscription costs commonly supplement
systems with upfront capital costs and cover software subscriptions and analytics.
• Cost per program (fixed fee)
Sometimes, service providers give a total estimate on a project basis. How the total estimate is
calculated may not be evident, but it could depend on facility density, remoteness, environment,
etc. Most of the time, fixed costs are provided per survey and vary with the scope (number of
facilities or length of the pipelines) and deployment frequency. Usually, cost per survey decreases
when covering more assets and at higher deployment frequencies (such as semi-annual
screenings / quarterly screenings, etc).
Cost information is not publicly available for most methane measurement companies and products.
In Table 19 below, Highwood provides a high-level initial cost assessment for the technologies
evaluated in the different scenarios.
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Table 19. Cost Estimates
Technology Upfront Cost per
Unit 5 (USD)
Annual Recurring
Cost per Personnel
(USD)
Annual Cost per
Program - Fixed fee
(USD)
Handheld Device (FID and
Hiflow samplers)1
$15,000
($3,000 per year)
$50,000
-
Vehicle (based on Picarro
costs)2
$1,200,000
($240,000 per year)
$110,000
-
Aerial (based on Bridger
Photonics)3 - - $ 12,000,000
Satellite (based on GHGSat) 4 - - $10,000,000
1 Source: Measurement of Methane Emissions: Abandoned Wells & Mines.
2 Estimated based on Picarro quote for EGI. Hybrid cost approach, which includes upfront capital for hardware, ongoing
subscription costs for the associated software and cost per unit time to cover the technician time performing the survey.
Different pricing options are available for this technology.
3 Estimated based on a signed project of Bridger with SoCal Gas. Considering that EGI DO infrastructure encompasses a
larger area, costs will potentially be higher. Estimate for one survey at the entire DO infrastructure.
4 Estimated based on Satelytics cost of ~$120K for 4 analyses in 100-200 km2 area.
5 Cost per hardware unit (one handheld device or one truck system). To determine the total upfront cost, the cost per unit
was multiplied by the number of personnel needed (which varied depending on the technology and deployment
frequency). To project the annual cost, the total upfront cost was evenly spread across a five-year period. Overall annual
upfront cost is detailed in the results (section 8.4.1).
LDAR-Sim Analysis
LDAR-Sim was used in the quantitative analysis of the explored FEMP scenarios. LDAR-Sim is an open-
source, agent-based numerical model developed at the University of Calgary used to predict the
emissions reduction effectiveness of different FEMPs and work practice configurations. LDAR-Sim
works by building a “virtual world” of oil and gas infrastructure and emissions sources that are
informed by empirical measurement data and historical environmental data. Different FEMP scenarios
are then applied to the virtual world to predict emissions reductions and compare performance
amongst the programs.
LDAR-Sim uses a geospatial approach to simulating LDAR, accounting for actual facility locations and
local environmental conditions anywhere in the world. In this case, historical Canadian weather data
was used. All relevant LDAR-Sim information can be found on the LDAR-Sim GitHub page and a
detailed description of LDAR-Sim can be found in Fox et al. 2019xxx.
Figure 9 presents a graphical overview of the LDAR-Sim virtual world, the programs which are applied
to this virtual world and some of the parameters which inform both. Note that the figure encompasses
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all possible LDAR-Sim inputs, but not all were used in this investigation such as vented/routine
emissions, and the price of carbon. LDAR-Sim is intentionally designed such that non-relative input
parameters can be ignored and will have no impact on results.
Figure 9. LDAR-Sim virtual world and program interaction. All bullet points are informed by the LDAR-Sim user, using empirically derived
data specific to the region and infrastructure being simulated whenever possible.
Figure 10 is an overview of the LDAR-Sim processes from setting up the simulation through to the
processes that happen while the simulation is running.
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Figure 10. The LDAR-Sim process. Before the “simulated time” begins the virtual world is constructed. Once “virtual time” begins, the
simulated emissions are randomly generated and crews travel between facilities detecting these emissions, eventually leading to their
repair.
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Key LDAR-Sim input assumptions
LDAR-Sim has over 100 parameters which allow for the fine-tuning of the sites in the virtual world (the
size and frequency of emissions they generate) and the performance / behaviour of the technologies
and methods (minimum detection limit, travel speed, survey speed, operational weather envelopes,
etc.). A full breakdown of LDAR-Sim operation and parameterization can be provided upon request;
however, this section will describe the most relevant parameters to be aware of when interpreting
simulations results.
• Minimum Detection Threshold: The smallest methane emission rate a particular technology
can detect. Minimum detection threshold in LDAR-Sim can be expressed as either a probability
of detection (PoD) curve, or a single threshold cut-off value when probability of detection data
is lacking. The following minimum detection thresholds (and their source) were applied to the
modeled methane detection / quantification technologies:
o Satellite: A detection threshold cut-off of 100 kg /hr CH4 was applied. In modelling, any
emission larger than 100 kg /hr CH4 is detected by the satellite. This cut off is sourced
from the whitepaper by McKeever and Jervisxxxi. Note, this whitepaper provides a PoD
curve for GHGSat with a 50% PoD at 100 kg /hr CH4, as such, modelling the satellite
detection threshold a cut-off value of 100 kg /hr CH4 (essentially 100% PoD at 100 kg /hr
CH4) is an optimistic interpretation of satellite performance.
o Aerial: The aerial method was assumed to have 90% PoD for rates ≥0.5 kg CH4. This PoD
is sourced from the Bridger Photonics website stated 90% PoD for the distribution
sectorxxxii, with further details available in Thorpe et al.xxxiii.
o Vehicle and Handheld: The PoD of the vehicle and handheld technology is based on a
PoD curve from Tian et al. xxxiv with coefficients representing leak rate, survey speed,
survey distance (sensor to source), Monin-Obukhov length, wind speed, and air
temperature. This PoD curve was applied to both vehicle and handheld modeled PoD
considering that both would use similar sensor ( in the study a high-precision gas
analyzer GasScouter™ G4301, Picarro, Inc. with 0.1 ppb measurement precision at a 1
Hz measurement interval was used), but differ in survey speed and distance, which can
be accounted for via changing the coefficient values of the PoD Curve. Figure 11 shows
the Tian et al. PoD curve and the following tables show how the coefficients were
parameterized for the modeled handheld and mobile methods.
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Figure 11. Handheld and Vehicle Detection Probability (DP, referred to as Probability of Detection (PoD) elsewhere in this report)
Table 20. Handheld and Vehicle Parameters
Method Leak Rate,
wind speed, air
temperature
Travel Speed Estimated
Distance from
the Source
Monin-Obukhov
Length1
Handheld (walking) Simulation
dependent
0.8 km/hr
(0.47 mph)
5 m 3
Vehicle (driving) Simulation
dependent
35 km/hr
(22 mph)
5 m 3
1 The Monin-Obukhov length characterizes the balance between buoyancy forces and shear forces within the atmospheric
boundary layer. Positive values indicate stable atmospheric stratification (i.e., buoyancy dominates over shear) while
negative values indicate unstable stratification (i.e., shear dominates over buoyancy).
• Infrastructure Subtypes: Subtyping is the process in which LDAR-Sim sites are grouped
according to shared characteristics. In this investigation, the following subtypes were used,
each assumed to have unique emissions behavior which therefore behaved differently from a
modeled emissions standpoint. Distribution stations were not subtyped into legacy service
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areas because data to characterize how those assets differ in terms of emissions profiles was
not available.
o Legacy Union Gas (LUG) Main Pipelines
o Legacy Union Gas (LUG) Service Pipelines
o Legacy Enbridge Gas (LEG) Main Pipelines
o Legacy Enbridge Gas (LEG) Service Pipelines
o Distribution Stations (gate station, district station or farm taps)
o Industrial/Commercial Meter Sets
• Infrastructure Modeled: The most granular piece of infrastructure in LDAR-Sim is a “site”,
which depending on the infrastructure could represent a specific length of pipeline or a unique
station as described below:
o 1 site = 10 km of pipeline (service and main).
o 1 site = 1 distribution Station (gate station, district station or farm taps).
o 1 site = 1 customer meter Set (either residential, industrial, or commercial).
Modeling every single asset was impractical due to constraints in computing capacity. Therefore, we
applied a scaling factor to represent a subset of the infrastructure. This approach doesn't compromise
the accuracy or reliability of the final results because the subtype distribution within the subset
mirrors that of the entire infrastructure. Due to the increased number of customer meter sets we had
to model this part of infrastructure separately. Considering the infrastructure size we chose scaling
factors of 1/100 and 1/10,000 for pipelines + distribution stations and customer meter sets,
respectively. This decision was based on computational constraints, the requirement for
representativeness, and the desired level of details. The raw subtype counts as well as the modeled
counts with the applied scaling factor are provided in Table 21.
Table 21: Summary of the subtype counts and scaling factors.
LDAR-Sim Infrastructure: Pipelines +
Distribution Stations
Raw Distance or Counts
Provided by EGI
Modeled Infrastructure (scaling
factor = 1/100)
Pipeline Main LUG 40,031 km 400 km
Pipeline Main LEG 34,516 km 350 km
Pipeline Service LUG 31,231 km 310 km
Pipeline Service LEG 38,886 km 390 km
Distribution Stations 1 19,453 stations 195 stations
LDAR-Sim Infrastructure: Meter Sets Raw Counts Provided by
EGI
Modeled Infrastructure (scaling
factor = 1/10,000)
Residential Meter Sets 3,874,241 stations 387 stations
Industrial/Commercial Meter Sets 66,391 stations 7 stations
1 Includes gate stations, district stations and farm taps.
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Leak Production Rate: The probability a leak will arise at a given site on a given day. EGI data was
used to inform the LEG and LUG pipeline subtypes while two key publicly available sources; a peer-
reviewed journal article from Lamb et al.xxxv and a preprint journal article from Coleman et al.xxxvi were
used to inform the distribution stations, and customer meter set subtypes. In addition, an EGI
estimate was used to confirm the distribution stations subtype leak production rate sourced from
Lamb et al. The leak production rates for each subtype are provided in Table 22.
Table 22. Summary of the subtype leak production rates
Subtype Average Annual Leaks per 10km
of Pipeline or Station
Leak Production Rate
LUG Main 0.15 0.0004
LUG Service 3.72 0.0102
LEG Main 0.19 0.0005
LEG Service 4.89 0.0134
Distribution Station 3.03 0.0083
Residential Meter Sets 0.19 0.0005
Industrial/Commercial Meter Sets 1.40 0.0038
Leak Rate Source: Informs the size (emission rate) of randomly generated leaks in simulation. Quantified emission rates from Lamb et
al.xxxvii and Coleman et al.xxxviii were used to inform simulated leak rates for all subtypes except industrial/commercial meter sets, in
which EGI quantification data was used. Hi-Flow samplers were used to quantify emission rates in Lamb et al.xxxix and Coleman et al. xl,
with the addition of a high precision analyzer when rates were too small. The leak rate sources for each subtype are provided in Table 23
Table 23. Summary of the subtype leak rate source for each subtype
Subtype Leak Rate Source
Reference Data
Data
Points
Average
Leak Rate
(g CH4/hr)
Maximum
Leak Rate
(g CH4/hr)
Minimum
Leak Rate
(g CH4/hr)
LUG Main Lamb et al. (Main) 160 47.03 2102 0.07
LUG Service Lamb et al. (Service) 93 12.53 199 0.10
LEG Main Lamb et al. (Main) 160 47.03 2102 0.07
LEG Service Lamb et al. (Service) 93 12.53 199 0.10
Distribution Stations Lamb et al. (M&R) 691 26.58 2769 0.02
Residential Meter Sets Coleman et al. 7 0.09 0.40 0.00039
Industrial / Commercial Meter Sets Enbridge 48 0.53 2.53 0.00043
High-Level Measurement Uncertainty Modelling Investigation
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Included in this LDAR-Sim analysis is a high-level investigation into the measurement uncertainty of
the explored FEMP Scenarios. The goal of this analysis was to investigate how a few key sources of
uncertainty (represented as LDAR-Sim input parameters) can impact measurement uncertainty.
This investigation is not a robust investigation into measurement uncertainty of the explored
scenarios. It is assumption-heavy with regards to important considerations like emissions behavior of
the virtual world, and detection thresholds of the methane detection and quantification technology. In
addition, it does not consider quantification error. Quantification error is a measure of how accurately
methane detection and quantification technologies can quantify emission rates from their raw data
products. Quantification error is poorly understood (minimal controlled testing has been conducted),
so for this investigation we assume all technology “perfectly” quantifies emission rates. Finally, this
investigation assumes all modeled technologies are capable of emission rate quantification. As
discussed earlier in this Section (8.3), the “Every 7 year Scenario” is a hypothetical FEMP scenario that
assumes all detected leaks are quantified via Hi-Flow sampler. To conduct a robust measurement
uncertainty analysis, many high-quality data are required, outside the scope of what many oil and gas
operators typically have access to, however, this is changing as more operators are considering
measurement informed inventories.
While the assumptions of this investigation must be kept front of mind, it does provide some
preliminary insights into how 3 key sources of uncertainty can affect measurement uncertainty:
• Detection threshold of the technology.
• Survey/screening frequency of the technology.
• Necessary assumptions around emissions durations.
The detection threshold and screening/survey frequency of the explored FEMP scenarios are
described above and in Section Error! Reference source not found.. In a measurement campaign b
ased on routine measurements, all measurements are a “snapshot in time,” and as such, emissions
duration must be assumed. Here, we adopt the conservative assumption that when an emission is
detected and measured, it has existed since the previous survey/screening when no emission was
found. Future work can explore different emissions duration assumption methodologies. The impacts
of the 3 key modeled sources of uncertainty will be discussed in more detail in Sections 0 and 8.5.
8.3.2. Qualitative Analysis
The following were key considerations undertaken in the qualitative analysis. The qualitative analysis
is discussed in more detail in Section 8.5.
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Scenario Evaluation Methods
To determine the optimal deployment program from the scenario analyses, Highwood considered
which of the scenarios offered the best combination of performance (number of leaks detected),
survey time (costs and resources of deploying the surveys) and cost.
The scenarios which had the strongest performance in terms of leaks detected vs time requirements
were progressed to the next level of the analysis, which was a more detailed discussion and
evaluation of the scenario uncertainty and its ability to improve the accuracy of the emissions
inventory estimate. Note that an assessment of the uncertainty impacts of all scenarios is available in
the scenario analysis spreadsheet included in the appendix. The discussion in this report is limited to
the scenarios with better performance.
Evaluation of uncertainty
When evaluating the potential uncertainty and accuracy impacts of each of the FEMP scenarios, an
assessment of the primary sources of uncertainty associated with each program was completed. To
narrow the analysis and focus on sources of uncertainty for comparison, Highwood reviewed sources
of uncertainty associated with the measurements of each FEMP scenario, as well as the spatial
extrapolation uncertainty and the temporal extrapolation uncertainty.
Additionally, the detection and quantification capabilities of the technologies are discussed for each
scenario. Some of the technologies included within the scenarios, such as handheld devices, are only
capable of methane detection, while others have detection and quantification capabilities (keep in
mind that in the quantitative analysis, we assume all scenarios incorporate measurement, sometimes
using a hypothetical Hi-Flow sampler in the handheld based scenarios). The detection-only programs
that are discussed in this qualitative analysis are highly sensitive but do not provide any information
about emission rates, so they offer limited opportunities for developing emission factors or
understanding leak sizes and distributions. Technology options which can perform quantification but
have a higher detection threshold, such as aerial screenings via Bridger Photonics, may not capture as
many leaks compared to a more sensitive technology like the vehicle-based surveys, but these can be
used to measure higher emitting sources for more targeted mitigation of large leaks.
Detection and quantification capabilities are a key consideration, as they contribute to how the results
from leak detection programs can be applied to inventory calculations and will affect the accuracy of
those calculations.
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Opportunity and Risk Assessment
For each of the scenarios, risks and opportunities were identified and discussed. For each, a relative
risk or opportunity was assigned (low, medium, high), with an explanation of the level provided.
Development of Company-Specific Emission Factors
Highwood also qualitatively evaluated the possibility of sampling a “representative” part of the
population for the development of company-specific emission factors. In this case, measurements
would be performed on the representative sample.
Conducting representative measurements would allow for a smaller number of measurements to be
performed, which would reduce the resource requirements, compared to conducting full scale
quantification programs. The ultimate purpose of developing company-specific measurement-derived
emission factors is to improve the accuracy of the fugitive emissions inventory for the distribution
segment.
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8.4. Quantitative Analysis Results
8.4.1. Survey Time, Personnel and Cost
Survey Time and Personnel
Figure 12. Survey time of the explored single technology FEMP scenarios. Bar height represents the total number of days required per
year across all crews for each method assuming 8 hours per day shifts.
is a bar chart visualizing the total survey time for the single FEMP scenarios.
Figure 12. Survey time of the explored single technology FEMP scenarios. Bar height represents the total number of days required per
year across all crews for each method assuming 8 hours per day shifts.
The number of crews (personnel) required to complete the surveys for each scenario was also
evaluated. This analysis considered the method deployment window (April – October, which was
considered to be 120 working days) and 8-hour work shifts. For this analysis, we considered 1 crew = 1
employee.
The following is a summary of the required crews for each FEMP scenario to ensure all surveys are
completed:
• Annual Handheld: 560 personnel
• Semi-Annual Vehicle: 189 vehicles
67,150
22,700 22,383
11,350 9,593
85 00
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
Annual
Handheld
Semi-Annual
Vehicle
Handheld -
Every 3
years
Annual
Vehicle
Handheld -
Every 7
years
Annual
Aerial
Annual
Satellite
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• Handheld - Every 3 years: 187 personnel
• Annual Vehicle: 95 vehicles
• Handheld - Every 7 years: 80 personnel
• Annual Aerial: 1 aircraft (surveys completed in less than 120 days)
• Annual Satellite: 0 crews (this method does not require personnel to survey the site)
This does not include support staff to assist with leak surveys and investigations (such as planning,
classification, etc.), repairs, and personnel needed for data analysis.
Cost
Based on the assumptions described in section 8.3.1, the cost of deployment was estimated. For
handheld and vehicle-based methods, the number of required personnel was used to estimate the
required hardware and dedicated employees. Table 24 and Figure 13 summarize the results.
Table 24. Estimation of annual cost of deployment.
Method
Total Annual
Upfront Cost 5
(USD)
Total Annual
Recurring Cost
(USD)
Annual Cost per
Program - Fixed
fee (USD)
Total
Annual Handheld $ 1.7 MM $ 28.0 MM - $ 29.7 MM
Semi-Annual
Vehicle $ 45.4 MM $ 20.8 MM - $ 66.2 MM
Handheld - Every
3 years $ 0.6 MM $ 9.3 MM - $ 9.9 MM
Annual Vehicle $ 22.7 MM $ 10.4 MM - $ 33.1 MM
Handheld - Every
7 years $ 0.2 MM $ 4.0 MM - $ 4.2 MM
Annual Aerial - - $12.0 MM $ 12.0 MM
Annual Satellite - - $10.0 MM $ 10.0 MM
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Figure 13. High-level cost analysis for different methods evaluated. The annual component of upfront cost considers overall upfront cost
distributed in 5 year-period.
Main limitations for the above analysis:
• Both aerial and satellite methods are new technologies for distribution surveys. The cost to
deploy an aerial method (based on Bridger Photonics) was estimated based on a pilot project
with SoCal gas, which has a DO segment concentrated in a smaller area.
• The above analysis does not consider the increase in resources that will be required for ground
follow-up to locate/repair leaks. This increase is expected to be higher for all non-walking
technologies compared with handheld due to poor location accuracy of vehicle/aerial options.
Each technology type will have different follow-up, data management, and repair costs
associated with it.
• Programs with upfront capital costs (vehicle and handhelds) have this value amortized, but this
is not the case for other costs. Therefore, the number of surveys and duration of the program
matter. For example, if you compare a ground-based vehicle system (with upfront costs) to an
aircraft-based survey for a one-year period, it will look worse than if you compare costs over a
five-year period.
• Another complexity with cost is whether the solution providers have leveraged economies of
scale. For example, some aerial and satellite companies will survey entire regions at once, not
just targeting the assets of a single operator. They can therefore offer lower per-site costs
U$ 0 MM
U$ 10 MM
U$ 20 MM
U$ 30 MM
U$ 40 MM
U$ 50 MM
U$ 60 MM
U$ 70 MM
Annual
Handheld
Semi-Annual
Vehicle
Handheld -
Every 3 years
Annual Vehicle Handheld -
Every 7 years
Annual Aerial Annual SatelliteAnnual Deployment Cost (USD)Annual Cost per Program - Fixed fee
Total Annual Recurring Cost
Total Annual Upfront Cost
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because these are offset by other companies “subscribing” to the same service. These and
other factors make it very difficult to acquire and estimate costs.
• Costs are always evolving as the methane monitoring innovation landscape is new and
evolving, and competitive pressures and the presence of venture capital for some companies
may temporarily bias costs.
Ultimately, it is critical to acquire and compare quotes from different vendors for specific programs
determined to be of interest to an operator. The above complexities also underline the critical
importance of conducting pilots, which often reveal hidden and unanticipated costs.
8.4.2. Emissions Mitigation and Leak Counts Modelling Results
The bar charts of Figures 14 to 17 are the results of LDAR-Sim emissions modelling. The bar length in
the “Percent of Leaks Detected” visualizations represents the proportion of all randomly generated
leaks in simulation detected by each of the explored FEMP Scenarios. The expected mitigation if all
leaks detected were repaired in 30 days was also evaluated and included in the appendix for
reference.
Across all scenarios, both the Annual Vehicle and Annual Handheld methods demonstrated a
comparable number of detected leaks. This happens because both methods use highly sensitive
sensors, enabling the detection of even minor sources under favourable deployment conditions.
Typically, trucks overlook some minor sources due to their increased distance from the emission point
and higher speed, which impacts their likelihood of detecting such leaks. Consequently, if only a
single pass were considered for both methods deployed in the same environmental conditions,
handheld devices would detect more leaks. Nevertheless, truck work practices modelled here involve
six passes, significantly mitigating the discrepancy between the two methods. While each pass by a
truck may have a lower chance of detecting a leak, visiting the same spot multiple times compensates
for this, resulting in a similar overall detection rate between the two methods.
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Pipelines (LUG and LEG) and Distribution Stations
Single Technology FEMP Scenarios
Figure 14. Percent of all randomly generated leaks (based on the subtypes and their associated leak production rates) detected by the
explored single technology FEMPs in an LDAR-Sim “virtual world” populated by pipelines and Distribution Stations
0%
76%
0%
77%
25%
10%
87%
0%20%40%60%80%100%
Annual Aerial
Annual Handheld
Annual Satellite
Annual Vehicle
Handheld - Every 3 years
Handheld - Every 7 years
Semi-Annual Vehicle
% of Leaks Detected from Overall Number of Leaks
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Multiple Technology FEMP Scenarios
Figure 15. Percent of all randomly generated leaks (based on the subtypes and their associated leak production rates) detected by the
explored multiple technology FEMPs in an LDAR-Sim “virtual world” populated by pipelines and Distribution Stations
80%
78%
77%
77%
87%
0%20%40%60%80%100%
Multi Tech FEMP Scenario 1 (Handheld -
1x/year
Vehicle 1x/ year
Aerial 1x/year)
Multi Tech FEMP Scenario 2 (Handheld -
Every 3 years
Vehicle - 1x/ year
Aerial - 1x/year)
Multi Tech FEMP Scenario 3 (Vehicle - 1x/
years
Aerial - 1x/year)
Multi Tech FEMP Scenario 4 (Handheld -
Every 7 years
Vehicle 1x/ year)
Multi Tech FEMP Scenario 5 (Handheld -
Every 7 years
Vehicle 2x/ year)
% of Leaks Detected from Overall Number of Leaks
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Residential, Industrial, and Commercial Meter Sets
Single Technology FEMP Scenarios
Figure 16. Percent of all randomly generated leaks (based on the subtypes and their associated leak production rates) detected by the
explored single technology FEMPs in an LDAR-Sim “virtual world” populated by residential, industrial, and commercial meter sets.
0%
75%
0%
77%
25%
10%
86%
0%20%40%60%80%100%
Annual Aerial
Annual Handheld
Annual Satellite
Annual Vehicle
Handheld - Every 3 years
Handheld - Every 7 years
Semi-Annual Vehicle
% of Leaks Detected from Overall Number of Leaks
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Multiple Technology FEMP Scenarios
Figure 17. Percent of all randomly generated leaks (based on the subtypes and their associated leak production rates) detected by the
explored multiple technology FEMPs in an LDAR-Sim “virtual world” populated by residential, industrial, and commercial meter sets.
8.4.3. Measurement Uncertainty Modelling Investigation Results
The bar charts of Figures 18 to 21 are the results of the high-level measurement uncertainty
investigation. The following is a summary of how to interpret the bar distances of these visualizations.
The blue bar represents the average “true” yearly emissions under each FEMP scenario. LDAR-Sim is
“omniscient” in that it “knows” how long each emission in simulation lasts. For example, if an
emission arose on day 100, was detected via a survey or screening on day 200 and repaired on day
205, LDAR-Sim “knows” the emission lasted for 105 days. LDAR-Sim multiplies each emissions
emission rate by this “known” / “true” duration to calculate the total “true” emissions used to
construct the blue bar. These calculations are then averaged across all years of simulated time. The
blue bar varies between different programs because LDAR-Sim assumes that once a leak is detected
78%
75%
74%
75%
84%
0%20%40%60%80%100%
Multi Tech FEMP Scenario 1 (Handheld -
1x/year
Vehicle 1x/ year
Aerial 1x/year)
Multi Tech FEMP Scenario 2 (Handheld -
Every 3 years
Vehicle - 1x/ year
Aerial - 1x/year)
Multi Tech FEMP Scenario 3 (Vehicle - 1x/
years
Aerial - 1x/year)
Multi Tech FEMP Scenario 4 (Handheld -
Every 7 years
Vehicle 1x/ year)
Multi Tech FEMP Scenario 5 (Handheld -
Every 7 years
Vehicle 2x/ year)
% of Leaks Detected from Overall Number of Leaks
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by screening technologies, it will be repaired within 30 days. For comparison purposes, a bar
representing emissions in the absence of an LDAR program (labeled "None") was also included. Since
repairs due to LDAR programs are not happening in this scenario, the "None" bar can be interpreted as
the maximum "true" emissions under the assumptions used in the modelling conducted for this
report.
The orange bar represents the average “estimated” yearly emissions under each explored FEMP
scenario. A real-world FEMP which incorporates measurement and lacks continuous monitoring (as
these modeled FEMPs do) must make assumptions around emission duration. For example, if an
emission arose on day 100, was detected via a survey or screening on day 200 and repaired on day
205, the FEMP campaign does not “know” that the emission arose on day 100, only that it was first
detected on day 200. As such, an assumption must be made regarding its duration. Here, the
assumption is the conservative one that assumes the emission has existed since the previous
survey/screening, where no emission was detected. In the above example, if the previous
survey/screening where no emission was detected was day 50, the FEMP must assume the emission
lasted for 155 days. Using these assumption estimates, the same logic as the blue “true” bar is then
used to calculate average yearly “estimated” emissions. Because of this assumption, FEMPs with long
time deltas between surveys/screenings are forced to likely overestimate emissions duration.
As well as emissions duration assumptions, the reader must also consider the impact of “seeing”
more leaks on uncertainty. One input parameter which impacts this is the detection threshold of the
modeled technologies. A technology with a lower detection threshold (handheld analyzer) can “see”
more emissions than one with a larger detection threshold (aerial screenings via Bridger Photonics).
The other input parameter which impacts this is survey frequency; the more frequently a technology
surveys/screens for emissions, the more emissions it can “see”.
The interplay between what emissions are “seen” and emissions duration estimation is perhaps best
shown in Figure 18 when comparing the estimated emissions in the “Handheld - Every 7 years” and
the “Handheld - Every 3 years” scenarios. The Handheld - Every 3 years scenario estimates more
emissions despite it applying a shorter duration assumption onto each emission it “sees”. With our
emissions duration assumptions in mind, the Handheld - Every 7 years could potentially assume a
duration of greater than 3 years, whereas the maximum assumed duration under the Handheld - Every
3 years program is 3 years. The likely cause is that the Handheld - Every 3 years program is “seeing”
more emissions, specifically, more large emissions due to the increased survey frequency and
therefore is estimating more overall emissions. This assumes an inflection point in the impact of
emissions duration vs. “seen” emissions (at a certain point, surveying more frequently while
decreasing the emissions duration assumption will “see” enough emissions to lead to larger
estimates). Assessing uncertainty is difficult as all factors must be considered in tandem.
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Pipelines (LUG and LEG) and Distribution Stations
Single Technology FEMP Scenarios
Figure 18. The "estimated" and "true" emissions of explored single technology FEMPs in an LDAR-Sim “virtual world” populated by
pipelines and distribution stations. The “emissions” are calculated by multiplying the emission rate of a leak by its duration and
summing all volumes. This is done for each year of simulated time, and the average values are shown. “true” emissions (blue bars)
represent the emissions where the leak duration is “known” by LDAR-Sim and incorporated into the emissions calculation. The
“estimated” emissions (orange bars) represent emissions where the leak duration must be estimated. Both “true” and “estimated”
emissions consider the detection capabilities of the FEMP’s technology.
0 kt 5,000 kt 10,000 kt 15,000 kt 20,000 kt
None
Annual Aerial
Annual Handheld
Annual Vehicle
Handheld - Every 3 years
Handheld - Every 7 years
Semi-Annual Vehicle
Methane Emissions (per year)
"Estimated" Emissions "True" Emissions
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Multiple Technology FEMP Scenarios
Figure 19. The "estimated" and "true" emissions of explored multiple technology FEMPs in an LDAR-Sim “virtual world” populated by
pipelines and distribution stations. The “emissions” are calculated by multiplying the emission rate of a leak by its duration and
summing all volumes. This is done for each year of simulated time, and the average values are shown. The “true” emissions (blue bars)
represent the emissions where the leak duration is “known” by LDAR-Sim and incorporated into the emissions calculation. The
“estimated” emissions (orange bars) represent emissions where the leak duration must be estimated. Both “true” and “estimated”
emissions consider the detection capabilities of the FEMP’s technologies.
0 kt 5,000 kt 10,000 kt 15,000 kt 20,000 kt
None
Multi Tech FEMP Scenario 1 (Handheld -
1x/year
Vehicle 1x/ year
Aerial 1x/year)
Multi Tech FEMP Scenario 2 (Handheld -
Every 3 years
Vehicle - 1x/ year
Aerial - 1x/year)
Multi Tech FEMP Scenario 3 (Vehicle - 1x/
years
Aerial - 1x/year)
Multi Tech FEMP Scenario 4 (Handheld -
Every 7 years
Vehicle 1x/ year)
Multi Tech FEMP Scenario 5 (Handheld -
Every 7 years
Vehicle 2x/ year)
Methane Emissions (per year)
"Estimated" Emissions "True" Emissions
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Residential, Industrial, and Commercial Meter Sets
Single Technology FEMP Scenarios
Figure 20. The "estimated" and "true" emissions of explored single technology FEMPs in an LDAR-Sim “virtual world” populated by
residential, industrial, and commercial meter sets. “Emissions” are calculated by multiplying the emission rate of a leak by its duration
and summing all volumes. This is done for each year of simulated time, and the average values are shown. The “true” emissions (blue
bars) represent the emissions where the leak duration is “known” by LDAR-Sim and incorporated into the emissions calculation.
“estimated” Emissions (orange bars) represent emissions where the leak duration must be estimated. Both “true” and “estimated”
emissions consider the detection capabilities of the FEMP’s technology.
0 kt 200 kt 400 kt 600 kt 800 kt 1,000 kt 1,200 kt
None
Annual Aerial
Annual Handheld
Annual Vehicle
Handheld - Every 3 years
Handheld - Every 7 years
Semi-Annual Vehicle
Methane Emissions (per year)
"Estimated" Emissions "True" Emissions
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Multiple Technology FEMP Scenarios
Figure 21. The "estimated" and "true" emissions of explored multiple technology FEMPs in an LDAR-Sim “virtual world” populated by
residential, industrial, and commercial meter sets. The “emissions” are calculated by multiplying the emission rate of a leak by its
duration and summing all volumes. This is done for each year of simulated time, and the average values are shown. The “true” emissions
(blue bars) represent the emissions where the leak duration is “known” by LDAR-Sim and incorporated into the emissions calculation.
“estimated” emissions (orange bars) represent emissions where the leak duration must be estimated. Both “true” and “estimated”
emissions consider the detection capabilities of the FEMP’s technologies.
0 kt 400 kt 800 kt 1,200 kt
None
Multi Tech FEMP Scenario 1 (Handheld -
1x/year
Vehicle 1x/ year
Aerial 1x/year)
Multi Tech FEMP Scenario 2 (Handheld -
Every 3 years
Vehicle - 1x/ year
Aerial - 1x/year)
Multi Tech FEMP Scenario 3 (Vehicle - 1x/
years
Aerial - 1x/year)
Multi Tech FEMP Scenario 4 (Handheld -
Every 7 years
Vehicle 1x/ year)
Multi Tech FEMP Scenario 5 (Handheld -
Every 7 years
Vehicle 2x/ year)
Methane Emissions (per year)
"Estimated" Emissions "True" Emissions
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8.5. Qualitative Analysis – DO Segment
8.5.1. Summary of the results – Distribution (DO)
Each FEMP scenario was modeled and assessed to evaluate the potential of using measurement to
reduce the uncertainty in the fugitive emissions inventory.
It is important to note that the results of the simulation modeling are only as strong as the input data.
When modelling the FEMP scenarios on EGI’s distribution system, Highwood used a combination of
EGI company data and literature values to characterize the leak frequency (leak production rate) and
leak size (leak rate source). These results should be considered with the caveat that there is a
potential that EGI’s leaks are not well characterized by the literature values which were used as inputs
into the simulations.
Of the methods evaluated, aerial and satellite were found to be unsuitable for deployment on EGI’s
DO system due to the dominance of small leaks typical of distribution systems.
Satellites did not detect any emissions in the simulations. Satellites do not have sufficiently sensitive
sensors to compensate for the large distance from the sensor to the source, and the leaks present
within a typical distribution network are not large enough to be detected by satellite. Highwood
evaluated claims by satellite monitoring providers that they were sufficiently sensitive to be effective
for use on distribution systems but was unable to validate those claims from any published data.
Aerial-based programs, specifically LiDAR-based helicopter-mounted systems, were also not found to
be effective for deployment on EGI’s DO system due to the technology sensitivity being too high
compared to the size of most leaks present within a typical distribution system. While aerial programs
are in use by gas utilities in North America, Highwood’s assessment is that the objective of those
programs is to detect large sources, prioritize repairs and reduce overall emissions. While effective
from a mitigation point of view, currently available aerial-based methods still miss most sources
(sources with emission rates below the technology detection limit) and, for that reason, are not
recommended to be used as a measurement tool to improve the accuracy of fugitive emissions
inventories.
Vehicle-based and handheld programs demonstrated the best-simulated performance of the
technologies evaluated. Handheld programs performed very similarly to vehicle-based programs in
terms of estimated cost, mitigation potential and number of leaks detected. While the time to
complete a walking survey was estimated to be 6 times more than vehicle programs, directly
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impacting service cost, the upfront cost of acquiring vehicle-mounted systems to survey the entire
infrastructure made the cost between the two options competitive. Both handheld and vehicle-based
surveys were simulated to be effective in detecting leaks, with a similar likelihood of finding
emissions. Handhelds are more sensitive because they take measurements close to the source of
emissions, but the protocol includes only one pass, while the vehicle-based protocol involves six
passes over the same location, increasing the likelihood of detecting the source. According to the
uncertainty analysis described in section 8.4, both methods are expected to have comparable
performance in terms of detecting leaks when deployed at the same frequency. However, it's essential
to note that the quantification error was not considered in the analysis. The two methods have
different quantification methodologies that can impact the accuracy of the final estimate. Hi-flow
samplers are used for direct measurement of emissions, while vehicle-based systems use plume
dispersion modeling to estimate emissions. Although hi-flow samplers are expected to have better
accuracy, we cannot confirm this due to the lack of controlled release studies focusing on the
quantification error associated with these technologies.
8.5.2. FEMP Scenario Outcomes and Trends
The use of methane measurement technologies, and more frequent deployment of these technologies
will reduce uncertainty in the calculated fugitive emissions inventory. Completing surveys on a more
frequent basis will provide “stops” to the temporal extrapolation of leak duration assumptions, thus
reducing the uncertainty of how long the leak has been occurring for.
EGI’s currently deployed LDAR program (handheld walking survey using detection only gas analyzer) is
expected to be more effective at detecting emissions than aerial methods but is not able to measure
any leak rate.
Within this scenario analysis, the detection of a greater number of leaks is advantageous due to the
emissions inventory calculation's dependency on the multiplication of the activity factor by the
emission factor. A higher percentage of the "average number of leaks detected per year" signifies a
FEMP scenario that approaches the detection of all existing leaks within the system, thereby
enhancing the accuracy of the activity factors. It should be noted that having a better understanding of
the number of leaks that occur does not necessarily improve knowledge of how large those leaks are
and the associated emissions. Therefore, handheld surveys should be complemented with Hi-flow
sampler measurement for a complete understanding of emissions if walking surveys are chosen.
Trade-offs exist between increasing survey frequency (thus increasing the time required to complete
those surveys and the associated costs and resourcing) and improvements in the mitigation and
accuracy of a measurement-informed inventory. Across all scenarios evaluated, the number of
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detected leaks increases as survey frequency increases. Completing any survey program more than
annually increases accuracy, but the associated time and cost increases are higher than the
performance benefits and are likely not worthwhile.
8.5.3. FEMP Scenario Uncertainty
For an overview of the uncertainties and impacts on the inventory accuracy of all assessed scenarios,
consult the scenario analysis spreadsheet included in the appendix.
Detection Uncertainty
The performance of vehicle-mounted sensing technology and handheld devices at detecting leaks has
been independently validated through controlled release testing on gas distribution systems globally.
For both the vehicle and handheld systems, most vendors deploy very sensitive sensors, but there is
still a potential that very small leaks below the detection threshold exist in the system. Picarro trucks,
for example, use CRDS methane sensors, which is the same technology modeling was based on. Work
practice (number of passes, proximity of the source, speed…) also has a significant impact on the
technology performance, but as modelling shows, under appropriate work practices, major sources
are consistently detected by both methods. Therefore, the uncertainty in the non-detection from
handheld and vehicle measurements is much lower than the uncertainty in the non-detection from the
less sensitive technologies which were evaluated (aerial and satellite).
Detection and Quantification Capabilities
Both handheld and vehicle-based FEMP scenarios are capable of detection and quantification of
methane emissions. However, additional time and resources are associated with the quantification of
emissions.
For vehicles, multiple passes are required to quantify the emissions. Onboard anemometers measure
wind speed and direction, which are used for plume dispersion modeling and source localization. The
modeled scenarios all considered the recommended six-pass protocol, so there is quantification
capability in these modeled scenarios. However, for the purpose of developing company-specific
emission factors, the level of granularity in the source localization may be insufficient from vehicle-
based detections. For example, a vehicle-based system can detect an emission and quantify its rate,
but it may not be able to determine the exact leaking source, posing a potential challenge for
developing company-specific emission factors.
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For handheld systems, detection and quantification can happen concurrently. Typically, the actual
leak rate is quantified directly with a Hi-flow sampler, instead of inferred from dispersion modeling.
Direct measurement is expected to have a lower uncertainty as there is less incoming required data
streams like with plume modelling, but there is a lack of controlled release studies assessing the
quantification accuracy of both.
For all technologies capable of quantification, quantification error needs to be considered.
Quantification error is only recently starting to be investigated in more detail in the research space.
All underground infrastructure (such as gas mains and service lines) poses an additional challenge
since the emitting source is buried under roadways and through yards, and methane gas permeation
through the different surface materials is required before being measured in the air. Source
localization may not always be possible without costly excavations, so the emission factors may be
developed by less granular source categories (e.g. “pipeline- main” instead of “pipeline- main:
threaded connection”). In addition, surface permeability may reduce the gas concentration available
to be detected by any leak detection technology.
Spatial Extrapolation Uncertainty
All scenarios evaluated assumed complete coverage of the DO system would be achieved (as close to
100% coverage as is reasonably possible). For this reason, Highwood’s assessment did not identify
significant differences between special extrapolation uncertainty in the scenarios.
If there were certain sites or areas being omitted from the survey planning, then spatial extrapolation
uncertainty would increase, as EGI would be required to determine if those sites/areas were “like” the
areas which were measured and if those same measurements leak counts, and other assumptions
could be applied to the un-surveyed sites. This is important to keep in mind when developing
company-specific emission factors, as the larger the spatial extrapolation uncertainty is, the greater
the overall uncertainty as emissions factors are extrapolated out to the rest of the non-sampled
infrastructure.
Temporal Extrapolation Uncertainty
Extrapolation of the detected and quantified emissions to the full reporting period requires that
assumptions about the duration of emissions be made. The emission factors that are currently in use
to calculate EGI’s DO fugitive emissions inventory are annualized, so there are no considerations
required to estimate emissions duration.
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However, when deploying technology and using the quantifications to develop a measurement-
informed fugitive emissions inventory, estimating the total duration of the leak is a key consideration.
Two approaches are common in regulations: assume that the leak has been emitting continuously
since the last time a survey was performed or assume that the leak has been emitting for half the time
since the last survey (assumes intermittent emissions). In this investigation, the former assumption
was used. Leak detection survey frequency is a major driver in the calculation of total fugitive
emissions using either assumption. As such, scenarios which survey more frequently are associated
with reduced temporal extrapolation uncertainty.
When comparing the Annual Vehicle scenario and Multi Tech FEMP Scenario 4, there is a slightly
reduced temporal extrapolation uncertainty associated with Multi Tech FEMP Scenario 4, due to the
addition of the handheld survey program. As such, Multi Tech FEMP Scenario 4 is preferred in terms of
impacts on uncertainty in the emissions inventory.
8.5.4. Risks and Opportunities of Deployment of the Modeled FEMP Scenarios
For an overview of the identified risks and opportunities of all assessed distribution scenarios, consult
the scenario analysis spreadsheet included in the appendix. This discussion focuses on the key risks
and opportunities associated with the preferred scenarios: Annual Vehicle and Multi Tech FEMP
Scenario 4.
Risk 1: Vehicle technology limitations
Two limitations to consider with the vehicle-based FEMP Scenario are the reliance on favourable
meteorological conditions and the frequent inability to be proximal to emission sources. Vehicle
technologies rely on atmospheric modelling, which incorporates multiple data streams (methane
concentration, wind speed, wind direction, temperature, etc.) Customer meter sets, which make up
the single biggest population group of emitting sources, are not easily accessible by vehicle, nor are
distribution stations. Vehicles are well suited to use for linear features (pipelines), but access
limitations may prevent robust surveys on other sources. As such, vehicles may “miss” small plumes
if sufficient dispersion has occurred between the source and the vehicle sensor or if there are
obstructions preventing the plume from reaching the vehicle. In addition, during the vehicle screening,
the wind must be blowing toward the sensor from the source. This combination of the requirement for
favourable meteorological conditions along with the risk of dispersed emissions by the time they
reach the vehicle poses a risk.
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The opportunity to mitigate this risk is to deploy handheld technologies in tandem since those
accessibility challenges do not apply to the same extent. For this reason, Multi Tech FEMP Scenario 4
is preferred over the Annual Vehicle Scenario for improving the accuracy of the emissions inventory.
Risk 2: Safety requirements
The primary driver for EGI’s current handheld leak survey program is safety. At this time, it is not clear
if there are any safety implications associated with the implementation of other technologies (such as
vehicles). Future work can include performing comparative studies to better understand the
performance of vehicles compared with handheld options and determine whether total replacement
for LDAR programs would be advisable.
The opportunity to mitigate this risk is to continue deploying handheld surveys at the current frequency
while also deploying a vehicle-based survey. While the absolute performance of the Annual Vehicle
scenario is equal to the Multi Tech FEMP Scenario 4, and the total survey time is 45% less, EGI may be
required to continue performing handheld surveys.
In the absence of handheld survey safety requirements, it is not recommended that EGI eliminate
handheld surveys, due to the factors discussed with Risk 1 above.
Risk 3: LDAR-Sim inputs may not be representative of the leaks present within EGI’s DO system
As previously mentioned, the LDAR-Sim results must be caveated that the outputs are reflective of the
inputs. Due to the lack of directly measured leak rates from EGI’s distribution system, Highwood used
literature values as inputs into the simulations. While those literature values were obtained through
large-scale measurement campaigns on North American gas utility systems, and the results of the
studies were either peer-reviewed or in pre-print review, there is a possibility that the LDAR-Sim
results are not representative of EGI’s actual leak profile.
The opportunity to mitigate this risk is to perform a robust detection and measurement campaign and
compare the results to the literature values to determine similarity. By implementing any of the
proposed scenarios, EGI should be able to mitigate this risk.
8.6. Qualitative Analysis – STO Segment
The STO segment represents 16% of EGI’s total fugitive inventory. Of this portion, 73% of STO’s fugitive
emissions already incorporate measurement into the inventory.
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The current leak detection and measurement campaign conducted by the operator has proven to be
sufficiently effective, providing comprehensive data on emissions and leakages. The existing
methodologies and technologies employed have demonstrated reliability and accuracy in identifying
and quantifying leaks across the operational infrastructure. Continuous monitoring and periodic
surveys have ensured timely detection and response to any anomalies, maintaining regulatory
compliance and environmental stewardship.
Given the success and robustness of the current campaign, additional surveys or technologies may
not be necessary at this time, as they could potentially introduce complexity without significant added
value in terms of improving leak detection or measurement precision given the existing coverage and
materiality. It is advisable for the operator to continue leveraging the established methodologies and
technologies while remaining vigilant for any advancements that could further enhance their leak
detection and measurement capabilities in the future.
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9. Recommendations and Implementation Plan for EGI
Improving the accuracy of fugitive emissions reporting will require a combination of technological,
procedural, and operational enhancements. With DO representing 84% of EGI’s total fugitive
emissions, these recommendations prioritize DO, noting that 73% of STO’s fugitive emissions are
calculated using direct measurement. Highwood has provided the following recommendations for
EGI:
• Recommendation 1: Develop company-specific emission factors based on source-level
measurements for DO.
• Recommendation 2: Pilot mobile ground detection strategy for DO.
• Recommendation 3: Leverage data from Recommendations 1 and 2 to develop a
measurement-informed inventory for DO.
• Recommendation 4: Monitor advances in aerial and satellite performance.
9.1. Recommendation 1: Develop company-specific emission factors based on
source-level measurements for DO
EGI should implement a measurement program to develop company specific emission factors for DO.
Within the STO segment, EGI already uses measurement to inform the inventory of compressor station
and receipt-sales meter station leaks, which collectively represent 73% of fugitive emissions from the
STO segment.
EGI’s DO assets constitute 84% of the 2022 fugitive emission inventory. Within DO, all emission
sources are currently quantified using generic emission factors. The DO segment has high activity
counts (asset and component counts) that are relatively consistent over time and unlikely to change
relative to emissions. Without company-specific emission factors based on measurement data to
increase the accuracy of emissions, this will also continue to be a consistently large source category
based on activity, but more accurate emission factors could increase or decrease materiality. Generic
emission factors may not represent the specific characteristics of a company’s unique operating
parameters, including maintenance and repair practices or preventive policies.
It is recommended that EGI should begin developing company-specific emission factors (Section
5.3.2), using existing standards and frameworks, such as OGMP2.0, as guidance to help inform the
sampling strategy. These company-specific emission factors could be incorporated with
Recommendation 2’s pilot program to create a MII.
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Developing company-specific emission factors will require defining a statistically relevant sample
population (i.e., a representative group of emissions sources within the company that contributes to
emissions).
9.1.1. Identify & Categorize Emission Sources:
EGI can use the existing asset/source classifications as initial groupings of assets alongside features
that may provide distinct groupings. Groupings and sub-grouping can be based on populations of
sites/facilities (distribution stations, customer meter sets, etc), or a population of sources (equipment
type, operating status, process).
9.1.2. Prioritize Sources:
EGI should prioritize the emission sources based on their materiality or regulatory importance. For
DO, customer meter sets and service lines should be prioritized based on their materiality, collectively
contributing 63% of DO’s total fugitive emissions.
9.1.3. Select Representative Samples:
From each prioritized category, EGI should select representative samples that reflect the range of
emissions within that category. These samples should reflect typical operating conditions, equipment
types, and emission control measures where applicable. EGI can use industry guidance such as
OGMP 2.0 as outlined in Section 5.3.2. When developing a sampling strategy, EGI should consider
seasonal variations in emissions, production level fluctuations, or other factors that may affect
emissions rates.
9.1.4. Emissions Measurement:
Emissions flow rates should be measured for the selected representative sample, using suitable
technology.
9.1.5. Calculate & Apply Emission Factors:
EGI can extrapolate from the measurements to calculate emission factors for each population. Step 8
in the GTI Veritas Measurement and Reconciliation Version 2.0 protocol, Reconcile Inventories and
Estimate Measurement Informed Inventory, gives comprehensive guidance on extrapolating
measurement results to non-surveyed areas.
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EGI can then incorporate the emission factors into EGI’s inventory, reporting frameworks, and
decision-making processes. Company-specific emission factors, when updated regularly, can be
used to track emissions performance, set reduction targets, and prioritize mitigation measures. OGMP
recommends that factors should be reviewed annually to confirm they are still representative but does
not mandate a specific update frequency for the underlying emission factor data. Repeat programs
may demonstrate consistency or highlight where further investigation is required.
9.1.6. Documentation:
The documentation of sampling strategy, data collection methods, calculations, and resulting
emission factors is essential for the credible and transparent use of company-specific emission
factors. This documentation will also provide continuity for future measurement campaigns and
inventory management.
9.1.7. Validate and Refine:
As a reasonableness check, compare the calculated emission factors with industry benchmarks, or
third-party verification. Refine the factors as needed based on additional measurement data
collected.
9.2. Recommendation 2: Pilot Mobile Ground Detection Strategy for DO
More accurately quantifying fugitive emissions can be achieved by increasing detection and
incorporating measurement to develop a measurement informed inventory. Increased detection can
help determine more accurate leak occurrences and measurement can help determine leak sizes.
Both will contribute to a more accurate quantification of fugitive emissions.
EGI should consider piloting mobile ground detection for improved emissions quantification, as
detailed in Scenario 4 in Section 8.4. In Scenario 4 EGI would continue with their current compliance
handheld survey program on the distribution system and would introduce annual vehicle surveys. Our
modeling suggests that EGI will be able to achieve up to a 77% annual detection rate. This is an
increase of 67% over the every 7 year scenario leak detection rate (from 10% to 77%), and an increase
of 52% over the every 3 year scenario (from 25% to 77%) with a potential increase of 35% on potential
annual mitigation (from 5% every 7 years to 40% for the annual vehicle scenario). Importantly, this
would introduce measurement of EGI’s DO fugitive emissions, compared with the current distribution
leak survey methods that do not include leak flow rate measurements.
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Scenarios 1-3, which included aerial and satellite detection, are not recommended. According to
available controlled release test data (Section 6.5) and Highwood modeling, neither technology is
likely to be sensitive enough to detect expected leaks for EGI.
To pursue an expanded mobile ground detection strategy and to verify the assumptions modeled, EGI
should develop and execute a pilot and scale up plan with defined goals and stage gates.
9.2.1. Goal Setting and Objectives:
Define clear and achievable goals for the pilot program and determine a pilot size and scope. Utilize
accepted statistical methods to determine a statistical sample size. Specific goals can include:
• Comparing different measurement technologies
o Accuracy
o Detection threshold
o Level of investigation required
• Identifying potential areas of focus for further measurements
• Increasing the accuracy of leak counts and leak sizes
• Developing a measurement-informed emissions baseline for future comparisons
• Creating an evaluation process to determine scale-up feasibility based on results.
9.2.2. Designing the Pilot Program:
Develop a detailed plan outlining the scope, timeline, budget, and resources required for the pilot
program. Determine investigation thresholds that will require follow-up. Select a suitable sample for
the pilot program, prioritize high materiality areas and geographic groupings, accessibility, and
cooperation from stakeholders. Obtain vendor quotes and determine the specific handheld and
mobile ground lab technology and methodologies to be used for fugitive detection and measurement.
Decide on costing model – e.g., using 3rd party vendors or purchasing technologies for in-house
deployment. Train personnel involved in data collection, analysis, and interpretation to ensure
accurate and reliable results, as required.
9.2.3. Implementation:
Execute the pilot program according to the established plan. This includes deploying technology and
collecting data. Monitor progress closely and address any challenges or issues that arise during the
implementation phase.
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9.2.4. Data Analysis:
Analyze the data collected during the pilot program, identify trends, and evaluate the effectiveness of
detection and measurement methods. Compare the results with those determined using the current
emissions quantification methodology. Assess the impact of the measurement program and its
potential for scaling up. Investigate discrepancies and document findings.
9.2.5. Evaluation and Issue Identification:
Detail the findings, lessons learned, challenges, and recommendations from the pilot program. Seek
feedback and input for improving the program and address any concerns or suggestions.
9.2.6. Scaling Up and Integration:
Based on the outcomes of the pilot program, consider scaling up fugitive detection and measurement
efforts or piloting alternative technologies. Integrate the lessons learned and best practices into
broader environmental monitoring and mitigation strategies. Continuously monitor and update the
program to incorporate new technologies, regulations, technology, and methodology advancements.
9.3. Recommendation 3: Leverage Data from Recommendations 1 and 2 to
Develop a Measurement Informed Emissions Inventory
EGI should utilize the data collected in Recommendations 1 and 2 to start developing a MII for DO.
Highwood determined that 73% of EGI’s STO emissions are currently measured directly. Leveraging
the additional data collected will allow EGI to assess the impact on the inventory, prioritizing high
materiality sources, or sources with higher levels of uncertainty.
A MII improves confidence and defensibility of CH4 emission estimates and can help to prioritize
emissions mitigation efforts. Several voluntary initiatives provide frameworks for developing a MII,
including GTI Veritas, MiQ, and OGMP 2.0.
While the current regulatory reporting framework in Canada does not yet require reconciliation of
different estimates, inventories integrating advanced measurement data are more robust than
inventories which are built using only one methodology.
9.4. Recommendation 4: Monitor Advances in Aerial and Satellite Performance
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EGI is advised against adopting aerial and satellite technology at this time, as it lacks the sensitivity
required to detect most leaks expected from EGI's distribution assets. Therefore, these technologies,
as they stand, are unlikely to enhance the accuracy of fugitive emissions monitoring on distribution
assets.
Instead, EGI is encouraged to stay abreast of advancements and controlled release testing data
related to aerial and satellite technology. This involves evaluating new data and options to determine
their relevance to distribution monitoring. Additionally, EGI could consider piloting Bridger Photonics'
next-generation sensor at low altitudes (e.g., using helicopters), given the positive feedback and
ongoing collaboration reported by SoCal Gas with Bridger Photonics.
Below, we expand on aerial and satellite monitoring, discussing their detection limitations, along with
an emerging model under early testing phases specifically designed for detecting emissions from
buried pipelines. It's crucial to note that technology is continually evolving, and decisions should be
based on the most up-to-date information available.
9.4.1. Aerial Monitoring
While aerial detection has become a common practice in the upstream industry, use in distribution
systems remains novel and widespread adoption has not yet occurred. Under Highwood simulation
aerial monitoring, based on Bridger Photonics’ established parameters (90% detection) for aerial
methods, is generally unable to detect leaks below 0.5kg/hr. Aerial monitoring is more suited to
identification of larger emitters than those typical of distributions systems.
Bridger Photonics has published a case study where they have been performing controlled double-
blind release testing with SoCalGas, the largest gas utility distributor in the United Statesxli. SoCalGas
signed a multi-year contract with Bridger in 2021 to continue to survey distribution assets, to detect
and reduce emissions. A second-generation Gas Mapping LiDAR sensor was set to be released,
capable of detecting 0.2kg/h but to our knowledge this limit has not yet been verified through
controlled release testing.
9.4.2. Satellite-Based Monitoring
Like aerial, satellites have not seen widespread adoption for distribution and are more commonly
used in upstream operations to detect larger emission sources. GHGSat under controlled release
testing has a detection threshold of 117 kg/hxlii, although in practice, has detected sources as low as
42 kg/h. A study released in 2023 conducted single-blind controlled methane release testing from up
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to five satellitesxliii. The results showed a detection range of 1,400 – 7,200 kg/h, with GHGSat able to
detect at 200kg/h. The study notes the suitability of this technology for deployment in high emitting
regions. Current satellites are unable to detect emissions characteristic of a distribution system,
which are mostly below 1 kg/h.
9.4.3. Emerging Technology – Sensor Network
A study published in January 2024xliv focused on the challenges of detecting methane, specifically
from buried pipelines. The study noted that the “current approaches of detection may not be suitable
to effectively monitor underground gas leaks under transient conditions due to cost, data
accessibility, deployment approach, and varied environmental conditions”.
Field testing conducted at METEC used Estimating the Surface Concentration Above Pipeline
Emission (ESCAPE) model to compare the methane detected above the surface with the belowground
near surface concentrations. The testing found that the belowground near surface concentrations
were 20% to 486% higher than the surface concentrations within a 4m monitoring radius under various
controlled test conditions. The testing conducted had release rates of 37 – 121 g/h and utilized low-
cost methane sensors calibrated against Picarro G4302. The study, performed on PVC pipe 0.91m
below ground, noted that the optimum number of sensors is 4 aboveground sensors within a 4m
radius of the leak area. This is an early model, which does not discuss the feasibility and practicality of
implementing 4 sensors every 4m in a distribution system. The study concluded that this was a tool to
assess risk and potentially prevent leakage but did not provide estimates of scope and cost of
deployment outside of the test environment.
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10. Conclusions
In conclusion, this report provides a comprehensive overview of EGI’s current greenhouse gas fugitive
emissions inventory and calculation methods. This report also provides recommendations for
improving the accuracy of EGI’s fugitive emissions inventory. By examining various methodologies and
technologies, the report underscores the critical importance of accuracy, efficiency, and compliance
in emissions reporting.
The recommendations outlined by Highwood provide a strategic roadmap for EGI to enhance the
accuracy and reliability of its fugitive emissions reporting. These recommendations direct EGI to focus
on DO emissions since they represent the majority of EGI's total fugitive emissions and are not
currently measured, unlike STO emissions. By focusing on DO and leveraging existing measurement
practices within the STO segment, EGI can make substantial progress in emissions quantification.
The first recommendation suggests the development of company-specific emission factors based on
source-level measurements for DO, prioritizing the most material sources. This approach, in
conjunction with prioritizing emission sources, selecting representative samples, and applying
rigorous measurement methodologies, can lead to more accurate emission factors tailored to EGI's
unique operational parameters. The documentation, validation, and refinement processes outlined
provide transparency and credibility in the use of these emission factors, crucial for informed
decision-making and regulatory compliance.
The second recommendation suggests piloting a mobile ground detection (vehicle) strategy for DO,
aiming to obtain flow rate measurements to work towards developing a measurement-informed
emissions inventory. By comparing different measurement technologies, identifying focus areas, and
setting clear objectives, EGI can inform its next steps based on outcomes of the pilot program. This
approach highlights the importance of gathering field data and meets the need for practical and
sensitive detection methods aligned with EGI's operational realities. In contrast, Highwood identified
limitations with aerial and satellite technologies and does not recommend their deployment on EGI’s
systems.
Furthermore, Recommendation 3 proposes the creation of a MII for DO, leveraging findings from the
company-specific emission factors and pilot program. This MII, guided by industry frameworks, would
enhance confidence and defensibility in EGI’s CH4 emission estimates, enabling EGI to prioritize
mitigation efforts and adapt to evolving regulatory requirements.
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Lastly, while cautioning against current aerial and satellite technologies, Recommendation 4 advises
EGI to monitor advancements in this field. Bridger Photonics' next-generation sensor underscores the
potential for future innovation in fugitive emissions monitoring.
In essence, these recommendations form a holistic approach to fugitive emissions management,
combining technological innovation, procedural rigor, and operational insights. By implementing
these strategies, EGI can improve the accuracy of its fugitive emissions and achieve a more accurate,
transparent, and proactive stance in addressing fugitive emissions, aligning with sustainability goals
and regulatory expectations.
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11. Appendix
11.1. Technology Table Summary
Transmission and Storage - Aircraft
Company Name
Technology
Name
Technology
Description
Equipment
Sensitivity (MDL)
Quantification
Performance
Survey Speed and
Coverage Environmental Limitations Other Considerations Controlled Release Testing
Source
Attribution
Capability
Bridger Photonics Gas Mapping
LiDAR
Active remote
sensing using
light detection
and ranging
(LiDAR)
3kg/hour or 0.5
kg/hour
Does detection
and quantification
Seconds-minutes
per site
Highest commercial uptake
of any of the aircraft-based
options,
METEC (multiple Adhoc
testings performed), also
have been subject to many
single-blind testings, results
of which have been
published in the literature.
Equipment
Level
FlyScan CHARM
Active remote
sensing using
differential
absorpotion
LiDAR (DIAL)
Not listed Detection and
quantification
Seconds-minutes
per site
Built and marketed
specifically for use on
pipelines
2023 testing was performed
at METEC, noted that only
detection was tested, there
was no localization or
quantification testing
performed
Equipment
Level
LaSen Alpis Helicopter
System
Active remote
sensing using
light detection
and ranging
(LiDAR)
10 kg/hour Detection and
quantification
Seconds-minutes
per site
Higher claimed MDL may be
too high for effective
detection of EGI's assets
N/A Equipment
Level
Boreal Laser GasFinder3-AB
Point sensing
using tunable
diode laser
absorption
spectroscopy
(TDLAS)
0.66 ppm Detection
185km/hour
helicopter travel
speed
Must fly through the
methane plume in order to
detect emissions
Boreal Laser is just a
manufacturer, there are
service providing vendors
worldwide
N/A Equipment
Level
Vanguard Pipeline
Falcon-XL Aerial
Methane
Detector
Point sensing
using tunable
diode laser
absorption
spectroscopy
(TDLAS)
unlisted- ppm
sensor
Detection (but
markets as real
time ppm
detection during
visual flyovers)
Seconds-minutes
per site
Must fly through the
methane plume in order to
detect emissions
ppm detection plus N/A Equipment
Level
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Transmission and Storage - Drones /UAV
Company Name
Technology
Name
Technology
Description
Equipment
Sensitivity (MDL)
Quantification
Performance
Survey Speed and
Coverage Environmental Limitations Other Considerations Controlled Release Testing
Source
Attribution
Capability
SeekOps SeekIR
Point sensing
(unknown
sensor type)
1 scf/hour
Detection and
quantification
(quantification is
performed in post-
processing using
dispersion
modeling
algorithms)
Whole sites, 1-5
sites/day
Many vendors use SeekOps
drone system and can be
hired as a third party
service, not necessarily
reliant on hiring SeekOps
directly
METEC (Adhoc testing
performed multiple times),
EDF Mobile Monitoring
Challenge (2018)
Equipment
Level
ABB HoverGuard
Point sensing
using TDLAS
sensor
0.05 kg/hour Detection and
quantification
Whole sites, 1-5
sites/day
ABB have not published or
updated materials about
the Hoverguard
product/service since
around 2020/2021.
Performance claims may be
outdated.
EDF Mobile monitoring
Challenge (2018) ** only
detection was tested, no
localization or
quantification was tested
Equipment
Level
ChampionX Scientific
Aviation Drone System
Point sensing
(unknown
sensor type)
unlisted Detection and
quantification
Whole sites, 1-5
sites/day Hired through a service
Advancing Development of
Emissions Detection (ADED)
2023
Equipment
Level
Baker Hughes Lumen Sky
Hybrid sensor
(assumed
combination of
point and active)
unlisted Detection and
quantification
Whole sites, 1-5
sites/day
No updates or other news
articles have been
published by Baker Hughes
about this technology since
2021, so performance claims
are likely to be outdated
and no longer accurate.
ADED Continuous
Monitoring Protocol (2020)
Equipment
Level
UAV systems are manned
by trained operators, so
constrained within a
regular workday, and
cannot fly in rain. All point
sensing drones require
wind to ensure more
accurate plume dispersion
modeling calculations.
Drones are subject to
Transport Canada
regulations and may
require special
authorization within
certain zones. Many
companies require specific
permission from
operations before
conducting drone surveys,
in order to fly closer to
equipment. Obtaining this
permission in advance, and
flying closer, improves
source delineation and
increases actionability of
results. Anecdotally,
results from drone surveys
are significantly impacted
by forest fire smoke
present in the air, and
should not be operated
during times of significant
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Transmission and Storage - Satellites
Company Name
Technology
Name
Technology
Description
Equipment
Sensitivity (MDL)
Quantification
Performance
Survey Speed and
Coverage Environmental Limitations Other Considerations Controlled Release Testing
Source
Attribution
Capability
GHGSat DATA.SAT
Passive Imagery
Satellite, uses
interferometer
sensing
technology to
look for
methane
absorption
spectra within
visible light, to
identify
Unlisted, but in
single-blind
testing, GHGSat
was able to
detect 0.2
tonnes CH4/hour
Detection and
quantification
near-
instantaneous
reliance on reflected
sunlight
200 kg/hour detection limit
is likely to be unsuitable for
use on EGI's assets.
Each satellite within the
GHGSat constellation
revisits a location every 14
days
Participation in single blind
testing, results have been
published in peer-reviewed
literature.
Facility /
Region Level
Satelytics Satelytics
Passive Imagery
Satellite, uses
interferometer
sensing
technology to
look for
methane
absorption
spectra within
visible light, to
identify
methane
emissions
35kg/hour?
Uses satellite data
to perform
detection and
quantification,
does not collect
this data
themselves
near-
instantaneous
reliance on reflected
sunlight
Satelytics uses the Maxar
satellite, and they have
algorithms which are used
to create a data product.
They are in an agreement
with Maxar to purchase
their data products to be
used for analytics.
Satelytics markets
themselves more heavily
for encroachment
monitoring, and liquids
leaks from pipelines (crude
and produced water)
METEC testing has been
performed, but Satelytics
has not participated in any
of these studies. Satelytics
has published internal
white papers, but results
from METEC have not been
peer-reviewed.
Facility /
Region Level
Kayrros Methane Watch
Passive Imagery
Satellite, uses
interferometer
sensing
technology to
look for
methane
absorption
spectra within
visible light, to
identify
Lowest
detection by
Kayrros (using
the Maxar
Worldview-3
satellite) was
100 kg/hour
Uses satellite data
to perform
detection and
quantification,
does not collect
this data
themselves
near-
instantaneous
reliance on reflected
sunlight
Kayrros uses the Maxar
WorldView-3 satellite, and
performs data analytics in a
similar way to Satelytics
Kayrros has participated in
single-blind peer reviewed
testing (results are still in
pre-print but have been
reviewed).
Facility /
Region Level
Maxar WorldView-3
Passive Imagery
Satellite, uses
interferometer
sensing
technology to
look for
methane
absorption
spectra within
visible light, to
identify
Smallest
detected leak by
Maxar in the
peer-reviewed
literature was
30kg/hour, but
majority of
emissions
detected are
over 100 kg/hour
Detection and
quantification
near-
instantaneous
reliance on reflected
sunlight
Many other companies are
using the Maxar satellites
for their own data analytics
purposes, and results from
the same plume (processed
by different analytics
companies) has been found
to be quite wide ranging
Maxar has participated in
single-blind peer reviewed
testing (results are still in
pre-print but have been
reviewed).
Facility /
Region Level
TROPOMI
TROPOMI
technology,
located on the
Sentinel-5
satellite, passive
imagery satellite
Very high Detection near-
instantaneous
reliance on reflected
sunlight
Detection limit from
TROPOMI is too high to be
useful to EGI.
Publicly available, free to
use and access data. Could
be used as a free resource
to check for extremely large
super-emitters.
Facility /
Region Level
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Transmission and Storage - Continuous Monitoring Systems (for use only at compressor stations, storage sites, or other discrete point source within STO)
Company Name
Technology
Name
Technology
Description
Equipment
Sensitivity (MDL)
Quantification
Performance
Survey Speed and
Coverage Environmental Limitations Other Considerations Controlled Release Testing
Source
Attribution
Capability
Qube Axon
Point sensor,
stationary
mounted on site
Detection,
quantification and
localization is
performed in post-
processing
Equipment
Level
Project Canary Sanary-S, Canary-
X
Point sensor,
stationary
mounted on site
Detection,
quantification and
localization is
performed in post-
processing
Equipment
Level
Scientific Aviation SOOFIE
Point sensor,
stationary
mounted on site
10kg/hour
Detection,
quantification and
localization is
performed in post-
processing
Equipment
Level
LongPath Frequency Comb
Laser
Laser-based
system with
reflectors
Much more expensive per
unit compared to other
continous monitoring
solutions, however each
individual sensor system
can cover a much larger
area. More suitable for
deployment in areas with a
higher density of sites, to
reduce the cost per site.
Equipment
Level
Kuva Kuva Gas Cloud
Imagine
OGI camera,
stationary
mounted on site
Unpublished,
assumed roughly
equal to OGI
sensitivity,
potential to be
worse due to
increased
distance away
from emitting
equipment.
Quantification
algorithms
OGI camera has to "see"
emissions, so careful
consideration should be
made to placement on site,
to maximize the likeliness
of detection
Equipment
Level
continuous
monitoring of
whole sites
Stationary point sensors
are reliant on wind; since
methane gas must pass
through the sensor in order
to be detected, wind
direction has a significant
impact on whether or not
emissions events are
detected. Because of this,
most continuous point
sensors are installed at
multiple locations within a
single site, to increase
detection probability
Company Name
Technology
Name
Technology
Description
Equipment
Sensitivity (MDL)
Quantification
Performance
Survey Speed and
Coverage Environmental Limitations Other Considerations Controlled Release Testing
Source
Attribution
Capability
Picarro Surveyor
Point sensor
using Cavity Ring-
Down
Spectroscopy
0-20 ppm
Detection and
quantification
(post-processing)
Picarro has seen the highest
uptake in use from leading
gas utility companies, as per
publications from those
companies.
Picarro markets themselves
specifically for effective use
on natural gas mains and
service lines within
distribution networks.
Picarro sensors have been
used in many leading peer-
reviewed studies on
methane emissions in
various parts of the natural
gas supply chain, especially
in A National Estimate of
Methane Leakage from
Pipeline Mains in Natural
Gas Local Distribution
Systems (Weller et al. 2020)
Region Level
Boreal Laser GasFinder3-VB Point sensor
using TDLAS 0.6 ppm Detection
The data produced from the
GasFinder3-VB (Vehicle
Based) is simply a 1-D Data
Plot that charts
concentration over time.
Post-processing can create a
2-D map showing where
No records of METEC testing
can be found, nor are there
any peer-reviewed
publications with
performance results from
the technology.
Region Level
Heath Consultants Discover AMLD Point sensor
Company
publication
states ppb range,
not verified
Detection and
quantification
(post-processing)
No records of METEC testing
can be found, nor are there
any peer-reviewed
publications with
performance results from
the technology.
Region Level
ABB MobileGuard Point sensor
using TDLAS 0.05 kg/hour
Detection and
quantification
(post-processing)
No specific vehicle-based
controlled release testing
has been performed at
METEC, but the drone-
mounted system uses the
same sensor, and the drone
was tested in 2018 as part of
the EDF Mobile Monitoring
Challenge.
Region Level
As fast as the car
that the system is
mounted on can
accurately
measure while
respecting local
speed restrictions.
Areas must be accessible
by vehicle
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Distribution - Drones
Company Name
Technology
Name
Technology
Description
Equipment
Sensitivity (MDL)
Quantification
Performance
Survey Speed and
Coverage Environmental Limitations Other Considerations Controlled Release Testing
Source
Attribution
Capability
SeekOps SeekIR
Point sensing
(unknown
sensor type)
1 scf/hour
Detection and
quantification
(quantification is
performed in post-
processing using
dispersion
modeling
algorithms)
Whole sites, 1-5
sites/day
Many vendors use SeekOps
drone system and can be
hired as a third party
service, not necessarily
reliant on hiring SeekOps
directly
METEC (Adhoc testing
performed multiple times),
EDF Mobile Monitoring
Challenge (2018)
Component
Level
ABB HoverGuard
Point sensing
using TDLAS
sensor
0.05 kg/hour Detection and
quantification
Whole sites, 1-5
sites/day
ABB have not published or
updated materials about
the Hoverguard
product/service since
around 2020/2021.
EDF Mobile monitoring
Challenge (2018) ** only
detection was tested, no
localization or
quantification was tested
Component
Level
Baker Hughes Lumen Sky
Hybrid sensor
(assumed
combination of
point and active)
unlisted Detection and
quantification
Whole sites, 1-5
sites/day
No updates or other news
articles have been
published by Baker Hughes
about this technology since
2021, so performance claims
are likely to be outdated
and no longer accurate.
ADED Continuous
Monitoring Protocol (2020)
Component
Level
UAV systems are manned
by trained operators, so
constrained within a
regular workday, and
cannot fly in rain. All point
sensing drones require
wind to ensure more
accurate plume dispersion
modeling calculations.
Drones are subject to
Transport Canada
regulations and may
require special
authorization within
certain zones. Many
companies require specific
permission from
operations before
conducting drone surveys,
in order to fly closer to
equipment. Obtaining this
permission in advance, and
flying closer, improves
source delineation and
increases actionability of
Distribution - Aerial
Company Name
Technology
Name
Technology
Description
Equipment
Sensitivity (MDL)
Quantification
Performance
Survey Speed and
Coverage Environmental Limitations Other Considerations Controlled Release Testing
Source
Attribution
Capability
Bridger Photonics
Gas Mapping
LiDAR
(helicopter)
Same LiDAR
technology as is
used by Bridger,
but mounted on
a helicopter,
specifically for
use on
distribution
systems (for
flying in cities
3kg/hour or 0.5
kg/hour
Does detection
and quantification
Seconds-minutes
per site
N/A - active sensor does
not require any interaction
with sunlight to detect
methane emissions.
Deployment platform
(helicopter) is likely to be
more limited in its
operation than the Gas
Mapping LiDAR sensor.
Successful deployments on
gas utilities in high-
population density areas
METEC (multiple Adhoc
testings performed), also
have been subject to many
single-blind testings, results
of which have been
published in the literature.
Region Level
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Distribution - Handheld
Company Name
Technology
Name
Technology
Description
Equipment
Sensitivity (MDL)
Quantification
Performance
Survey Speed and
Coverage Environmental Limitations Other Considerations Controlled Release Testing
Source
Attribution
Capability
OGI Optical gas
imaging camera
Each individual
component must
be searched for
emissions
Many service providers of
OGI surveys do provide a
quantification estimate, this
is typically based on visual
estimates of the leak size.
Yes Component
Level
QOGI
Optical gas
imaging camera,
plus
quantification
software (often
an accompanying
Slower than OGI,
since there is a
waiting period for
live
quantifications
Well established and
understood technology.Yes Component
Level
Hi-flow sampler
The Hi-flow
sampler
measures both
the flow rate of
the sampling
stream and the
methane
concentration
within that
stream, the
device calculates
methane
emission rates in
cubic feet per
minute (CFM) or
litres per minute
(LPM). Used
exclusively for
quantification
after an
emission has
been identified.
Sensitivity not
commonly
considered for
quantification-
only devices,
however, the
Hetek device can
quantify leaks
with flow rates
as low as 4.95
gph
Quantification
Two minutes for a
measurement as
per
https://energy.col
ostate.edu/wp-
content/uploads/s
ites/28/2022/08/F
ACF_High_Flow_Fi
nal_Report_ada.pd
f
Well established and
understood technology.
Yes, but likely unblinded as
detection performance is
not a concern for Hi-Flow
samplers.
Component
Level
Handheld gas
monitors
All handheld gas
analyzers which
meet EPA
Method-21
requirements.
Varies by make
and model. 1-10
ppm.
Detection
Similar to, but
more labor
intensive than
OGI, as the
operator must be
in direct proximity
to all components
requiring survey,
whereas they can
be observed from
a distance with
OGI.
Well established and
understood technology.Yes Component
Level
Various
Can be affected by
extreme temperatures and
high humidity levels, wind
flow, and air disturbances.
Heavy precipitation can
impact the viewability of
the OGI feed. Adverse
weathe conditions which
hamper the ability for a
"boots on the ground"
survey should also be
considered.
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11.2. Scenario Analysis
Program Name Methods- Frequency Description Key Assumptions Survey Time (per year)Emissions(kt of CH4 / year)Potential Annual Mitigation (kt of CH4 / year)Average number of leaks detected per year (%)Suitability for Use on EGI
Handheld - Every 7
years
Handheld - Every
7 years
Program uses handheld
technology to detect emissions
(every 7 years). Detected leaks
are evaluated and assigned a
relative risk level based on
measured concentration.
Detection probability increases with source rate.
Average survey speed of 0.75km/hr. Detection probability increases with source rate (minimum 95%). Performance
based on high-precision gas
analyzer (GasScouter™ G4301,
Picarro, Inc.). Similar peformance
expected for sensors with 1ppm
sensitivity and 1–10 Hz response
time. Deployment window: ~ 120 days from April to October.
9,593 days (~80 crews)
Pipelines and M&R: 17,412kt
Customer Metersets: 1,022kt
Overall:18,435kt
Pipelines and M&R: 922kt
(5%)
Customer Metersets: 51kt (5%)
Overall:973kt (5%)
Pipelines and M&R: 10k (10%)
Customer Metersets: 96k
(10%)
Overall:107k (10%)
This is the incumbent method that
is currently being used by EGI on DO system.
The scenario is technically
feasible for deployment but there
are significant performance
limitations.
To meet EGI's objective of reducing
the uncertainty in the reported fugitives inventory, this program is not well suited.
Annual Handheld Handheld - 1x/year
Program uses handheld
technology to detect
emissions. Detected leaks are
evaluated and assigned a relative risk level based on measured concentration. Detection probability
increases with source rate.
Same as above, but more frequent deployment.67,150 days (~560 crews)
Pipelines and M&R: 11,167kt
Customer Metersets: 664kt
Overall:11,831kt
Pipelines and M&R: 7,167kt
(39%)
Customer Metersets: 410kt
(38%)Overall:7,577kt (39%)
Pipelines and M&R: 79k (76%)
Customer Metersets: 739k (75%)Overall:818k (75%)
This program and scenario is roughly equivalent to the annual
vehicle program (below), and the
technology and method is well
established for use on distribution
systems.
This program is resource intensive and the total annual survey time required to complete one full walking survey of the system is
very high, especially when
considering that the mitigation
potential and the number of
detected leaks from the program is
equivalent to the vehicle surveys.
Program Name Methods- Frequency Description Key Assumptions Survey Time (per year)Emissions(kt of CH4 / year)Potential Annual Mitigation (kt of CH4 / year)Average number of leaks detected per year (%)Suitability for Use on EGI
Annual Vehicle Vehicle - 1x/year
Program uses a vehicle-based
technology to detect and
quantify emissions. Detection
probability increases with
source rate. Protocol includes
6 passes.
Average survey speed of 35km/hr.
Detection probability increases
with source rate (minimum 40%).
Peformance based on high-
precision gas analyzer with 1ppm
sensitivity and 1–10 Hz response
time. Deployment window: ~ 120 days from April to October.
11,350 days (~95 crews)
Pipelines and M&R: 11,063kt
Customer Metersets: 661kt
Overall:11,724kt
Pipelines and M&R: 7,272kt
(40%)
Customer Metersets: 412kt
(38%)
Overall:7,684kt (40%)
Pipelines and M&R: 80k (77%)
Customer Metersets: 752k
(77%)
Overall:832k (77%)
Yes, this program is suitable. The detection threshold of the technology is sufficiently low to detect small emissions present
within distribution systems, the
technology performance is
approximately equivalent to
walking surveys, and the survey
time is 1/6th of the walking survey.
The vehicle surveys include six passes of each location, whereas the walking surveys only pass each
location once.
Semi-Annual Vehicle Vehicle 2x/ year
Program uses a vehicle-based
technology to detect and quantify emissions 2x per year. Detection probability increases with source rate.
Protocol includes 6 passes.
Same as above, but more frequent deployment 22,750 days (~190 crews)Pipelines and M&R: 8,009ktCustomer Metersets: 491kt
Overall:8,500kt
Pipelines and M&R: 10,325kt (56%)Customer Metersets: 583kt
(54%)
Overall:10,908kt (56%)
Pipelines and M&R: 91k (87%)Customer Metersets: 846k (86%)Overall:937k (86%)
Yes, this program is suitable.
However, EGI should consider if
the significant increase in
resources required to complete 2
full system surveys (using the 6-pass protocol) per year are justified given that the program only performs 9% better. Potential
that the increases in performance
are marginal compared to the
increase in resources (and
associated costs).
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Program Name Methods-
Frequency Description Key Assumptions Survey Time (per year)Emissions
(kt of CH4 / year)
Potential Annual Mitigation
(kt of CH4 / year)
Average number of leaks
detected per year (%)Suitability for Use on EGI
Annual Aerial Aerial - 1x/year
Program uses a aircraft-based
technology to detect and
quantify emissions. Detection
is limited to sources above
0.5kg/hour.
Average survey speed of
110km/hr. Constant detection
probability of 90% of rates above
0.5kg/hr (does not detect any
source below). Performance based
on Bridger Photonics sensitivity
considering deployment at distribution sector. Deployment: August-October
85 days (~1 crew)
Pipelines and M&R: 15,854kt
Customer Metersets: 1,074kt
Overall:16,928kt
Pipelines and M&R: 2,480kt
(14%)
Customer Metersets: 0kt (0%)Overall:2,480kt (13%)
Pipelines and M&R: 460(
0.44%)
Customer Metersets: 0k (0%)Overall:460 (0.04%)
No, this method is not
recommended for full adoption on
EGI's DO systems. While the technology will detect some of the emissions from the distribution, it is not sufficiently sensitive to
capture enough of the smaller
emitters to reduce the uncertainty
in the emissions estimate.
Instead, this method could be
deployed for identification of super-emitting sources (or other large emitters) to allow for rapid repair and mitigation. However,
Highwood's desktop research
indicates that leaks which are
sufficiently large to be detected
through aerial methods are likely
to be reported by customers, due to
mercaptan scented additive in the gas.
Annual Satellite Satellite
Program uses a satellite to
detect and quantify emissions.
Detection is limited to sources above 100kg/hour.Method surveys the same location on a ~2 week periodicity.
Constant detection probability of
100% of rates above 100kg/hr
(does not detect any source below). Performance based on GHGSat sensitivity. ~ 120 days from April to October.
n/a Pipelines and M&R: 18,334ktCustomer Metersets: 1,074ktOverall:19,408kt
Pipelines and M&R: 0kt (0%)Customer Metersets: 0kt (0%)Overall:0kt (0%)
Pipelines and M&R: 0k (0%)Customer Metersets: 0k (0%)Overall:0k (0%)
No, satellites have not been proven
to be sufficiently sensitive to
detect any of the emissions which are characterized and described in the literature on distribution systems.
Program Name Methods- Frequency Description Key Assumptions Survey Time (per year)Emissions(kt of CH4 / year)Potential Annual Mitigation (kt of CH4 / year)Average number of leaks detected per year (%)Suitability for Use on EGI
Scenario 1
Handheld -
1x/year
Vehicle 1x/ year
Aerial 1x/year
Program considers a
combination of handheld,
vehicle and aerial-based
technologies.
Same assumptions as single
technology options.
Handheld - 67,150 days (~180
crews)
vehicle -11,350 days (~95
crews)
Aerial - 85 days (~1 crew)
Pipelines and M&R: 9,769kt
Customer Metersets: 600kt
Overall:10,369kt
Pipelines and M&R: 7,704kt
(44%)
Customer Metersets: 417kt
(41%)
Overall:8,122kt (44%)
Pipelines and M&R: 83k (80%)
Customer Metersets: 762k
(78%)
Overall:845k (78%)
this program is technically feasible, however this is not a
suitable program.
The addition of the aircraft does
not improve the performance of the
program to detect emissions, and
it will not improve accuracy of emissions invenotry estimates.
Scenario 2
Handheld - Every
3 years
Vehicle - 1x/ year
Aerial - 1x/year
Program considers a
combination of handheld
(every 3 years), vehicle and
aerial-based technologies.
Same assumptions as single
technology options.
Handheld - 22,383 days (~180
crews)
vehicle -11,350 days (~95
crews)Aerial - 85 days (~1 crew)
Pipelines and M&R: 9,815kt
Customer Metersets: 613kt
Overall:10,428kt
Pipelines and M&R: 7,659kt
(44%)
Customer Metersets: 404kt
(40%)Overall:8,063kt (44%)
Pipelines and M&R: 81k (78%)
Customer Metersets: 736k
(75%)
Overall:817k (75%)
this program is technically
feasible, however this is not a suitable program.
The addition of the aircraft does
not improve the performance of the
program to detect emissions, and
it will not improve accuracy of
emissions invenotry estimates.
Comparison of this scenario to scenario 1 indicates that reducing the handheld deployment frequency does not significantly
reduce the performance of this
program, and the performance of
this program is marginally
stronger than the vehicle-only
deployment.
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Program Name Methods-
Frequency Description Key Assumptions Survey Time (per year)Emissions
(kt of CH4 / year)
Potential Annual Mitigation
(kt of CH4 / year)
Average number of leaks
detected per year (%)Suitability for Use on EGI
Scenario 3
Vehicle - 1x/
years
Aerial - 1x/year
Program considers a
combination of vehicle and
aerial-based technologies.
Same assumptions as single
technology options.
vehicle -11,350 days (~95
crews)
Aerial - 85 days (~1 crew)
Pipelines and M&R: 9,842kt
Customer Metersets: 620kt
Overall:10,462kt
Pipelines and M&R: 7,631kt
(44%)
Customer Metersets: 397kt
(39%)
Overall:8,028kt (43%)
Pipelines and M&R: 80k (77%)
Customer Metersets: 729k
(74%)
Overall:810k (75%)
Similar to scenarios 1 and 2, the performance of the program is dominated by the performance of the vehicle.
Again, this scenario is not suitable
because the addition of the
aircraft does not add any
performance benefits, while
significantly increasing the cost and resources required to complete the program.
Scenario 4
Handheld - Every
7 yearsVehicle 1x/ year
Program considers a combination of handheld (every 7 years) and vehicle-based technologies.
Same assumptions as single technology options.
Handheld - 9,593 days (~80 crews)vehicle -11,350 days (~95 crews)
Pipelines and M&R: 10,529kt
Customer Metersets: 618ktOverall:11,147kt
Pipelines and M&R: 6,944kt
(40%)
Customer Metersets: 400kt (39%)Overall:7,344kt (40%)
Pipelines and M&R: 80k (77%)Customer Metersets: 733k (75%)Overall:813k (75%)
Yes, this is the recommended scenario.
Scenario 5
Handheld - Every
7 years
Vehicle 2x/ year
Program considers a combination of handheld
(every 7 years) and vehicle-
based (2x per year)
technologies.
Same assumptions as single
technology options.
Handheld - 9,593 days (~80
crews)
vehicle -22,750 days (~190
crews)
Pipelines and M&R: 7,584kt
Customer Metersets: 438kt
Overall:8,022kt
Pipelines and M&R: 9,890kt (57%)
Customer Metersets: 579kt
(57%)
Overall:10,469kt (57%)
Pipelines and M&R: 91k (87%)
Customer Metersets: 827k
(84%)
Overall:918k (85%)
This scenario is suitable but Highwood's assessment is that the
improvements of this program
against the single vehicle
deployment are not sufficient to
justify the additional resources
and cost associated with doubling
the vehicle deployment.
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11.3. Mitigation Plot
These are the results of complementary analysis to quantitative results in section 8.4, assuming all
leaks detected were repaired in 30 days. The bar length of the “Potential Mitigation (%)” visualizations
represent the proportion of simulated emission volume each FEMP Scenario mitigates compared to a
hypothetical FEMP devoid of any formal LDAR.
Emissions mitigation (expressed as a % of the total emissions in a hypothetical FEMP scenario devoid of any formal LDAR) by the
explored single technology FEMPs in an LDAR-Sim “virtual world” populated by pipelines and Distribution Stations.
14%
39%
0%
40%
12%
5%
56%
0%10%20%30%40%50%60%
Annual Aerial
Annual Handheld
Annual Satellite
Annual Vehiacle
Handheld - Every 3 years
Handheld - Every 7 years
Semi-Annual Vehiacle
Potential mitigation (%)
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Emissions mitigation (expressed as a % of the total emissions in a hypothetical FEMP scenario devoid of any formal LDAR) by the
explored single technology FEMPs in an LDAR-Sim “virtual world” populated by pipelines and Distribution Stations.
44%
44%
44%
40%
57%
0%10%20%30%40%50%60%
Multi Tech FEMP Scenario 1
(Aerial 1x/year + Vehicle 1x/year +
Handheld 1x/year)
Multi Tech FEMP Scenario 2
(Aerial 1x/year + Vehicle 1x/year +
Handheld every 3 years)
Multi Tech FEMP Scenario 3 (Aerial 1x/year
+ Vehicle 1x/year)
Multi Tech FEMP Scenario 4
(Vehicle 2x/year + baseline (handheld every
7 years)
Multi Tech FEMP Scenario 5
(Vehicle 1x/year + baseline (handheld every
7 years)
Potential mitigation (%)
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Emissions mitigation (expressed as a % of the total emissions in a hypothetical FEMP scenario devoid of any formal LDAR) by the
explored single technology FEMPs in an LDAR-Sim “virtual world” populated by residential, industrial, and commercial meter sets.
0%
38%
0%
38%
13%
5%
54%
0%20%40%60%80%100%
Annual Aerial
Annual Handheld
Annual Satellite
Annual Vehiacle
Handheld - Every 3 years
Handheld - Every 7 years
Semi-Annual Vehiacle
Potential mitigation (%)
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Emissions mitigation (expressed as a % of the total emissions in a hypothetical FEMP scenario devoid of any formal LDAR) by the
explored multiple technology FEMPs in an LDAR-Sim “virtual world” populated by residential, industrial, and commercial meter sets.
41%
40%
39%
39%
57%
0%20%40%60%80%100%
Multi Tech FEMP Scenario 1
(Aerial 1x/year + Vehicle 1x/year +
Handheld 1x/year)
Multi Tech FEMP Scenario 2
(Aerial 1x/year + Vehicle 1x/year +
Handheld every 3 years)
Multi Tech FEMP Scenario 3 (Aerial 1x/year
+ Vehicle 1x/year)
Multi Tech FEMP Scenario 4
(Vehicle 2x/year + baseline (handheld
every 7 years)
Multi Tech FEMP Scenario 5
(Vehicle 1x/year + baseline (handheld
every 7 years)
Potential mitigation (%)
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xv https://www.pnas.org/doi/full/10.1073/pnas.1805687115
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xviii Palmer, P. I., Peylin, P., … Zhuravlev, R. (2015). An intercomparison of inverse models for estimating sources and sinks
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xxi Fox, T., Strange, M., Hayman, A., & Moorehouse, B. (2022). (rep.). Leak Detection Methods for Natural Gas Pipelines.
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xxii Fox, T., Strange, M., Hayman, A., & Moorehouse, B. (2022). (rep.). Leak Detection Methods for Natural Gas Pipelines.
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xxiii Guide: Greenhouse Gas Emissions Reporting | ontario.ca. http://www.ontario.ca/page/guide-greenhouse-gas-emissions-
reporting.
xxiv Weller, Z. D., Hamburg, S. P. & von Fischer, J. C. A National Estimate of Methane Leakage from Pipeline Mains in Natural Gas
Local Distribution Systems. Environ. Sci. Technol. 54, 8958–8967 (2020).
xxv Product. CSA Group. (2022a, September 17). https://www.csagroup.org/store/product/CSA%20Z662:19/
xxvi How we build and maintain a safe pipeline - Enbridge Inc.. (n.d.-b).
https://www.enbridge.com/~/media/Enb/Documents/Factsheets/How we build and maintain a safe pipeline
USA.pdf?la=en
xxvii How do you monitor your crude oil pipeline system?. Enbridge Inc. (n.d.). https://www.enbridge.com/Your-
questions/Enbridge-FAQs/How-do-you-monitor-your-crude-oil-pipeline-system.aspx
xxviii Law document english view. Ontario.ca. (2018, November 19). https://www.ontario.ca/laws/regulation/180390
xxix Law document english view. Ontario.ca. (2018, November 19). https://www.ontario.ca/laws/regulation/180390
xxx Fox, T. A., Ravikumar, A. P., Hugenholtz, C. H., Zimmerle, D., Barchyn, T. E., Johnson, M. R., Lyon, D., & Taylor, T. (2019).
A methane emissions reduction equivalence framework for alternative leak detection and repair programs. Elementa:
Science of the Anthropocene, 7. https://doi.org/10.1525/elementa.369
xxxi McKeever, J., & Jarvis, D. (2022, September). Validation and Metrics for Emissions Detection by Satellite. Ghgsat.com.
https://www.ghgsat.com/en/scientific-publications/validation-and-metrics-for-emissions-detection-by-satellite/
xxxiixxxii What is methane detection sensitivity?. What is Gas Mapping LiDAR’s Detection Sensitivity? | Bridger Photonics.
(n.d.). https://www.bridgerphotonics.com/methane-detection-sensitivity
xxxiii Thorpe, M., Krietinger, A., Altamura, D., Dudiak, C., Conrad, B., Tyner, D., Johnson, M., Brasseur, J., Roos, P., Kunkel,
W., Carre-Burritt, A., Abate, J., Price, T., Yaralian, D., Kennedy, B., Newton, E., Rodriguez, E., Ibrahim Elfar, O., & Zimmerle,
D. (2024). Deployment-Invariant Probability of Detection Characterization for Aerial Lidar Methane Detection.
https://doi.org/10.31223/x5r96m
xxxiv Tian, S., Riddick, S. N., Cho, Y., Bell, C. S., Zimmerle, D. J., & Smits, K. M. (2022). Investigating detection probability of
mobile survey solutions for natural gas pipeline leaks under different atmospheric conditions. Environmental Pollution,
312, 120027. https://doi.org/10.1016/j.envpol.2022.120027
xxxv de Lange, A., & Landgraf, J. (2018, June 28). Methane profiles from GOSAT thermal infrared spectra. Atmospheric
Measurement Techniques. https://amt.copernicus.org/articles/11/3815/2018/
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Page 400
119
info@highwoodemissions.com
highwoodemissions.com
Technical Report
EGI Fugitive Emissions Measurement Report
Re
xxxvi Vollrath, C., Hugenholtz, C. H., Barchyn, T. E., & Wearmouth, C. (2024, March 12). Methane emissions from residential
natural gas meter set assemblies. SSRN. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4756001
xxxvii de Lange, A., & Landgraf, J. (2018, June 28). Methane profiles from GOSAT thermal infrared spectra. Atmospheric
Measurement Techniques. https://amt.copernicus.org/articles/11/3815/2018/
xxxviii Vollrath, C., Hugenholtz, C. H., Barchyn, T. E., & Wearmouth, C. (2024, March 12). Methane emissions from residential
natural gas meter set assemblies. SSRN. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4756001
xxxix de Lange, A., & Landgraf, J. (2018, June 28). Methane profiles from GOSAT thermal infrared spectra. Atmospheric
Measurement Techniques. https://amt.copernicus.org/articles/11/3815/2018/
xl Vollrath, C., Hugenholtz, C. H., Barchyn, T. E., & Wearmouth, C. (2024, March 12). Methane emissions from residential
natural gas meter set assemblies. SSRN. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4756001
xli https://www.bridgerphotonics.com/sites/default/files/inline-
files/Final%20Gas%20Mapping%20LiDAR%20for%20Distribution%20Utilities%20%281%29.pdf
xlii McKeever, J., & Jarvis, D. (2022, September). Validation and Metrics for Emissions Detection by Satellite. Ghgsat.com.
https://www.ghgsat.com/en/scientific-publications/validation-and-metrics-for-emissions-detection-by-satellite/
xliii Sherwin, E.D., Rutherford, J.S., Chen, Y. et al. Single-blind validation of space-based point-source detection and
quantification of onshore methane emissions. Sci Rep 13, 3836 (2023). https://doi.org/10.1038/s41598-023-30761-2
xliv Jui-Hsiang Lo, Kathleen M. Smits, Younki Cho, Gerald P. Duggan, Stuart N. Riddick,
Quantifying non-steady state natural gas leakage from the pipelines using an innovative sensor network and model for
subsurface emissions - InSENSE, Environmental Pollution, Volume 341, 2024, 122810, ISSN 0269-7491,
https://doi.org/10.1016/j.envpol.2023.122810.
Filed: 2024-05-31, EB-2024-0125, Exhibit D, Tab 1, Attachment 1, Page 119 of 119
Page 401
ENBRIDGE GAS INC.
Accounting Entries for
Fugitive Emissions Measurement Administration Deferral Account (FEMADA)
Account No. 179-342
The purpose of the account is to record the incremental costs associated with the
Fugitive Emissions Investigation Plan. The revenue requirement will include incremental
operating costs as well as costs associated with any required capital investment,
including return on rate base, depreciation expense, and associated income taxes.
Incremental costs are related to the implementation of measurement technologies,
configuration of IT systems, incremental staffing, consulting support and other
miscellaneous costs, including training, conferences, and memberships associated with
methane measurement technologies and methodologies. This account is for amounts
incurred on or after January 1, 2025.
Simple interest is to be calculated on the opening monthly balance of this account using
the OEB-approved EB-2006-0117 interest rate methodology. The balance of this
account, together with carrying charges, will be disposed of in a manner designated by
the OEB in a future rate application.
Account numbers are from the Uniform System of Accounts for Gas Utilities, Class A
prescribed under the Ontario Energy Board Act, 1998.
Debit Account No.179-342
Fugitive Emissions Measurement Administration Deferral Account
Credit - Account No. 728
General Expense
To record, as a debit/(credit) in the account, costs related to the technology pilot,
configuration of IT systems, incremental staffing, consulting support and other
miscellaneous costs, including training, conferences, and memberships associated with
methane measurement technologies and methodologies.
Debit Account No.179-342
Fugitive Emissions Measurement Administration Deferral Account
Credit - Account No. 323
Other Interest Expense
To record, as a debit/(credit) in the account, interest expense on the opening monthly
balance.
Filed: 2024-05-31
EB-2024-0125
Exhibit D
Tab 1
Attachment 2 Page 1 of 1
Page 402
Col. 1Col. 2Col. 3Col. 4Col. 5Col. 6Col. 7Line No. Contracted Union CapacityBudgeted Daily Contract Demand Volume Monthly Demand Toll Assumed in 2018 BudgetForecasted Annual Cost (2)Actual Daily Contract Demand VolumeMonthly Demand Toll Effective January 1, 2023 to December 31, 2023 Annual Cost (3)Balance in the 2023 S&TDA (4)(GJ)($/GJ) ($Millions)(GJ)($/GJ)($Millions) ($Millions)1 Union Gas Dawn to Lisgar67,929 2.865 2.3 67,929 3.190 2.6 2 Union Gas Dawn to Parkway2,792,173 3.402 114.0 2,792,173 3.760 126.0 3 Union Gas Dawn to Parkway - M12X200,000 4.239 10.2 200,000 4.648 11.2 4 Union Gas F24 T85,000 0.069 0.1 85,000 0.077 0.1 5 Union Transmission Costs126.6 139.8 (13.2) 6 Dawn T Service Costs(11.2) (16.9) 5.7 7 Federal Carbon Costs- 1.6 (1.6) 8 Union & Third Party Market Based Storage20.1 23.8 (3.7) 9 2021 Deferral Disposition - UG (1)- 5.9 (5.9) 10 Total135.5 154.2 (18.7) Notes(1) Transporation deferral adjustments related to 2021 S&TDA increased actual costs by $5.9MM12 Transport $5.9M, M16 Transport $0.1M, Federal Carbon ($0.1M)(2) Col. 1 * Col. 2 * 12(3) Col. 4 * Col. 5 * 12(4) Col. 3 - Col. 6Breakdown of the 2023 Storage and Transportation Deferral Account (2023 S&TDA) - EGD Rate ZoneFiled: 2024-05-31, EB-2024-0125, Exhibit D, Tab 1, Schedule 1, Page 1 of 1Page 403
Col. 1Col. 2Col. 3Col. 4 Col. 5Line No.Particulars2019 Transactional Services Revenue2020 Transactional Services Revenue2021 Transactional Services Revenue2022 Transactional Services Revenue2023 Transactional Services Revenue($000's)($000's)($000's)($000's)($000's)1 Storage Optimization 60.7 0.00.00.00.02 Transportation Optimization13,084.5 17,643.4 17,509.0 47,904.8 59,520.9 3 Transactional Services Revenue13,145.2 17,643.4 17,509.0 47,904.8 59,520.9 4 Amount Included in Rates12,000.0 12,000.0 12,000.0 12,000.0 12,000.0 5 Less Ratepayer Portion of TS11,830.7 15,879.1 15,758.1 43,114.3 53,568.8 6 TSDA sub-total169.3 (3,879.1) (3,758.1) (31,114.3) (41,568.8) 7 ETT Revenue - Rider H35.1 5.8 146.1 120.3 169.3 8 TSDA Total134.3 (3,884.9) (3,904.1) (31,234.7) (41,738.1) Breakdown of Transactional Services Revenue By Type of Transaction - EGD Rate ZoneFiled: 2024-05-31 EB-2024-0125 Exhibit D Tab 1 Schedule 2 Page 1 of 1Page 404
Col . 1Col . 2Col . 3Col . 4Col . 5Col . 6Col . 7Col . 8Col . 9 Col . 10Col . 11Col . 12Col . 13Line No.ParticularsJanFebMarAprMayJunJulAugSepOctNovDecTotal1Budget UAF (103m3)17,033 18,952 16,299 11,723 6,620 3,360 2,496 2,412 2,463 3,884 8,289 13,146 106,6772 PGVA Reference Price 282 282 282 187 187 187 172 172 172 187 187 1873 Budget UAF Dollar 4,809,129 5,350,826 4,601,949 2,191,296 1,237,370 628,008 430,523 415,945 424,794 724,752 1,546,672 2,453,024 24,814,2874Budget UAF based on actual throughput (103m3) (1)16,659 15,114 14,587 9,266 5,241 3,744 3,670 3,502 3,593 6,683 11,237 14,194 107,4885UAF Annual Variance (103m3) (2) (3)(4,379) (3,973) (3,834) (2,436) (1,378) (984) (965) (921) (944) (1,757) (2,954) (3,731) (28,255)6Total Actual UAF (103m3) (4)12,280 11,141 10,752 6,830 3,863 2,760 2,705 2,581 2,648 4,926 8,283 10,463 79,2327 PGVA Rate282 282 282 187 187 187 172 172 172 187 187 1878 Actual UAF Cost ($) (5) 3,467,113 3,145,553 3,035,817 1,276,689 722,119 515,931 466,489 445,147 456,698 919,178 1,545,552 1,952,221 17,948,5079 UAFVA Volume Variance (6)(4,753)(7,811)(5,547)(4,893)(2,756)(600)2091691851,042(6)(2,684)(27,445)10 UAFVA Cost Variance ($) (7)(1,342,016) (2,205,273) (1,566,132) (914,607) (515,252) (112,077) 35,96529,20331,904 194,426(1,120)(500,803) (6,865,780)11 Line Pack Gas (LPG) Allocation160,13112 2023 Damage Adjustment(217,040)13 Total 2023 UAFVA (8)(6,922,689)Notes(1) UAF volumes based on budget throughput percentage multiplied by actual throughput volumes(2) Line 5 = Line 6 - Line 4(3) UAF annual variance allocation based on actual throughput profile 15% 14% 14% 9% 5% 3% 3% 3% 3% 6% 10% 13%(4,379) (3,973) (3,834) (2,436) (1,378) (984) (965) (921) (944) (1,757) (2,954) (3,731) (28,255) (4) Line 4 + Line 5(5) Line 6 * Line 7(6) Line 6 - Line 1(7) Line 8 - Line 3(8) Line 10 + Line 11 + Line 12Breakdown of The 2023 Unaccounted-For Gas Variance Account (2023 UAFVA) - EGD Rate ZoneFiled: 2024-05-31 EB-2024-0125 Exhibit D Tab 1 Schedule 3 Page 1 of 1Page 405
Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8 Col. 9 Col. 10Col. 11Rate Class Budget Annual UseNormalized Actual Annual Use Normalized Usage Variance (1)Budget Customer MetersNormalized Volumetric Variance (2)DSM Budget DSM Actual DSM Volumetric Variance (3)Normalized Volumetric Variance Excluding DSM (4)Unit Rate AUTUVA: Revenue Impact, Exclusive of Gas Costs (5)(m3)(m3)(m3)(106m3) (106m3) (106m3) (106m3) (106m3) ($/m3)($Millions)1 2,360 2,308 (51.7) 2,135,521 (110.4) (4.2) (4.2) 0.0 (110.4) 0.0794(8.8)6 28,390 27,696 (693.8) 171,753 (119.2) (10.4) (10.4) 0.0 (119.2) 0.0465(5.5)Total(14.3)Notes(1) Col. 2 - Col. 1(2) Col. 3 * Col. 4(3) Col. 7 - Col. 6(4) Col. 5 - Col. 8(5) Col. 9 * Col. 102023 Average Use True Up Variance Account - EGD Rate ZoneFiled: 2024-05-31 EB-2024-0125 Exhibit D Tab 1 Schedule 4 Page 1 of 1Page 406
1
Enbridge Gas Inc. 50 Keil Drive N Chatham, Ontario N7M 5M1 Canada
September 21, 2022
Dear Recipient,
Subject: Storage at Dawn, injections commencing April 1, 2023
Enbridge Gas Inc. operating as Enbridge Gas Distribution (Enbridge Gas) requires firm natural
gas storage services with injections commencing April 1, 2023.
This storage service request is being administered by Ernst & Young LLP on behalf of Enbridge
Gas Inc.
Enbridge Gas is seeking a diverse portfolio of storage services that both meet and exceed the
minimum requirements below. This includes those that allow higher deliverability and access to multiple nomination windows for each gas day.
Enbridge Gas requires that these storage services meet the following specifications:
Term: Up to five (5) years commencing April 1, 2023. To encourage storage contracts term diversity, Enbridge Gas is seeking service offerings of various term lengths. The amount placed will be at Enbridge Gas’ discretion.
Term Potential to be contracted
1 - year 2 PJ’s
2 - year 2 PJ’s
3 - year 4.5 PJ’s 4 – year 4.5 PJ’s 5 - year 4.5 PJ’s
Location: Enbridge Gas will deliver gas to Storage Provider at Union Dawn for injection, and Storage Provider will re-deliver gas to Enbridge Gas at Union Dawn for withdrawal. If any
transportation capacity is included as part of the storage offering to facilitate Dawn injections and withdrawals, please provide details.
Firm Injection Requirements: Must include the months from May 1 through Sept. 30
Firm Withdrawal Schedule: Must include the months from Dec. 1 through March 31
Responses: Should you be interested in supplying this storage service to Enbridge Gas, please complete the attached Excel form, stating the delivery points, term, MSB and service attributes
Filed: 2024-05-31, EB-2024-0125, Exhibit D, Tab 1, Schedule 5, Page 1 of 2
Page 407
2
with the relevant pricing, including demand, commodity charges and other items indicated.1 Enbridge Gas also requires sample invoices.
Credit: Prior to deal execution, service providers must have sufficient open credit with EGI. The current high commodity price environment has had a significant impact on the credit position of potential counterparties and the available credit required to provide non-physical storage products. Providing EGI with 1 PJ of “synthetic storage” could require up to $12,000,000 CAD in available credit. Counterparties are welcome to contact EGI Credit to discuss their credit position.
The deadline to submit your proposal(s) is 11 a.m. Mountain Time (MT) on Oct. 11, 2022, after which time Enbridge Gas will contact the parties which submitted proposals that have been selected2. Please submit your proposal(s) to the attention of Chester Mercier at the e-mail
address provided below: Chester.Mercier@EY.com
All questions and responses are to be directed to Chester.Mercier@EY.com. Do not contact Enbridge Gas directly regarding this process.
The deadline for any queries is 12 p.m.(noon) Mountain Time (MT) on September 27, 2022. All queries and responses will be provided to all parties on Sept. 29, 2022. Additional Information: Enbridge Gas invites all potential participants to review a presentation
that has been posted to its website, in the Storage and Transportation section of its website, within News and Presentations. Enbridge Gas will contact successful bidders following the close of the RFP process.
Sincerely,
Chester Mercier
Ernst & Young LLP
1 This storage service request may have Dodd Frank Act implications and may require specific clauses to be included in any storage agreement between the parties. Any such storage agreement will not be binding until a definitive agreement is executed by the parties.
2 Please note that successful suppliers must meet all of Enbridge’s credit criteria. Enbridge, in its sole discretion and for whatever reason, may accept or reject any and all proposals. Enbridge reserves the
right at any time after the deadline to conduct negotiations with one or more of the bidders to the exclusion of others, and such negotiations may include changes to the storage service described in this letter.
Filed: 2024-05-31, EB-2024-0125, Exhibit D, Tab 1, Schedule 5, Page 2 of 2
Page 408
2022 Storage RFP ‐ Issued on 9/22/2022; Responses on 10/11/2022 ‐ All responses summary=RFP Manager recommendationsResponseTotal cost (CAD/GJ)Total Annual cost ‐ 1 turn ‐ CADTotal Annual cost ‐ 1PJ ‐ CADTerm (years) Volume (GJ)High/Low flexibilityMax Withdrawal rights ‐ % Ratchet score / # of days to w/dmax Injection rate (GJ/day)max Withdrawal rate (GJ/day)Days to InjectNotesREDACTED Filed: 2024-05-31, EB-2024-0125, Exhibit D, Tab 1, Schedule 6, Page 1 of 1Page 409
UNABSORBED DEMAND COSTS (UDC) VARIANCE ACCOUNT
UNION RATE ZONES
1. The balance in the UDC Variance Account is a debit from ratepayers of $0.042
million plus interest as of December 31, 2023, of $0.037 million, for a total of
$0.079 million. The $0.042 million balance is the difference between the actual UDC
incurred by the Union rate zones and the amount of UDC collected in rates, partially
offset by a credit to ratepayers related to a refund of Panhandle Pipeline tolls that
were applicable to UDC costs between 2020 and 2023.
1. UDC Recovery in Rates
2. To meet customer demands across the Union rate zones and to meet the planned
storage inventory levels at October 31, approved rates for the Union rate zones in
2023 included planned unutilized pipeline capacity of 11.3 PJ in Union North West,
3.1 PJ in Union North East and 0 PJ in Union South. The UDC volumes included in
2023 rates are based on the Gas Supply Plan filed in Union’s Dawn Reference Price
proceeding1.
3. As discussed in the Enbridge Gas 5 Year Gas Supply Plan2, in Union North, the
upstream transportation capacity (long-haul, short-haul and STS) is first sized to
meet the design day requirements. The amount of transportation capacity needed to
meet average annual demand requirements is less than the capacity required to
meet design day requirements. Therefore, a portion of contracted capacity for the
Union rate zones is planned to be unutilized. In a warmer than normal year, UDC
may be incurred in Union South, and additional UDC in Union North, to balance
supply with lower demands. The Union North and Union South transportation
portfolios are managed on an integrated basis and the pipeline to leave unutilized, if
necessary, is determined based on the least cost option. In the EB-2021-0149
1 EB-2015-0181, Exhibit A, Tab 2, Appendix A, Schedule 1.
2 EB-2019-0137, p. 82.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 1 of 55
Page 410
Decision for the disposition of the 2020 UDC Variance account, Enbridge Gas
agreed:
In future deferral and variance account clearance applications related to the
deferred rebasing term, Enbridge Gas agrees that it will include evidence
reporting on: UDC and transportation capacity released by rate zone, and the
costs and revenues transferred between rate zones.3”
4. Table 1 provides the capacity released by rate zone and the associated UDC costs
and/or revenue. The path released does not determine where the UDC costs or
associated revenue for the releases will be allocated. Instead, the costs and revenue
are allocated based on the portion of the UDC variance driven by each respective
rate zone, as can be seen in Table 2.
Table 1
Capacity Released & Related Costs Incurred
Line
No. Particulars
Union
North East
Union
North West
Union
South Total
(a)(b)(c)(d)
1 Capacity Released (TJ) 6,448 4,351 23,348 34,147
2 UDC Costs Incurred ($000s) 2,416 2,105 5,857 10,378
3 Released UDC Capacity ($000s) (32) (1,277)(48) (1,357)
5. Enbridge Gas collected $6.738 million in rates for UDC for the Union rate zones
during 2023 and recorded an associated interest debit of $0.037 million (see
Table 2). Actual UDC costs in 2023 were $10.378 million offset by $1.357 million in
released capacity value, resulting in a net cost of $9.021 million (see Table 3).
Actual UDC costs are allocated to Union North West, Union North East and Union
South in proportion to the actual supply and demand variances which occurred in
each respective area.
6. As discussed in Enbridge Gas’s April QRAM4, Enbridge Gas received a refund from
Panhandle Pipelines regarding over-recovery of costs of service of which $2.24
3 EB-2021-0149, Settlement Proposal, Exhibit N1, Tab 1, Schedule 1, October 4, 2021, p. 15.
4 EB-2024-0093, Exhibit D, Tab 1, Schedule 1, para 8.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 2 of 55
Page 411
million, including interest, pertained to UDC between 2020 and 2023. This amount
has been credited to the appropriate rate zones that bore the cost of the Panhandle
tolls as outlined in Line 6 of Table 2.
7. The variance between the amounts collected in rates and the actual UDC costs,
including the interest debit of $0.037 million, and the Panhandle Pipelines refund of
$2.24 million, results in a net debit from ratepayers in the UDC Variance Account of
$0.079 million.
8. The balance applicable to sales service and bundled DP customers in Union North
West is a credit of $1.608 million and in Union North East, a credit of $0.746 million.
There is a debit of $2.433 million applicable to sales service customers in Union
South.
9. Table 2 provides the derivation of the UDC variance account balances by
operational area.
Table 2
UDC Variance Account by Operational Area
Line
No. Particulars ($000s)
Union
North East
Union
North
West
Union
South Total
(a)(b)(c)(d)
1 UDC Collected in Rates (1,369) (5,370) -(6,738)
2 UDC Costs Incurred (Table 3) 993 4,870 3,158 9,021
3 Variance (line 1 + line 2) (376)(500)3,158 2,283
4 Interest (6)(8)52 37
5 (Credit)/Debit to Operations Area (382)(508)3,210 2,320
6 Panhandle Pipelines Refund Impact,
including interest (364)(1,100)(778)(2,241)
7 Total (Credit)/Debit to Operations Area (746) (1,608) 2,433 79
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 3 of 55
Page 412
The following is a description of each item in Table 2:
1.1 UDC Collected in Rates
10. The 2023 OEB-approved rates include $7.174 million of UDC associated with
14.4 PJ of planned unutilized pipeline capacity in Union North West and Union North
East and no planned unutilized pipeline capacity in Union South. The total cost of
UDC in rates assumes TransCanada Pipeline final tolls effective January 1, 2023.
On an actual basis in 2023, Enbridge Gas recovered $6.738 million in Union North
West and Union North East and $0.0 million in Union South.
1.2 UDC Costs Incurred
11. The actual unutilized capacity in 2023 was 34.1 PJ. The level of unutilized capacity
experienced in 2023 was largely due to planned unutilized capacity (and resulting
UDC) and lower customer use.
12. The costs reflected in the UDC Variance Account are the total demand charges for
unutilized pipeline capacity totaling $10.378 million, partially offset by $1.357 million
generated from releasing the pipeline transportation capacity to the market.
Unutilized upstream transportation capacity is released and sold on the secondary
market to minimize UDC. The value generated from the transportation releases is
credited to the UDC Variance Account mitigating the overall UDC impact as shown
in Table 3.
Table 3
UDC Costs Incurred
Line
No. Particulars ($000s)
Union
North East
Union
North West
Union
South Total
(a)(b)(c)(d)
1 UDC Costs Incurred 1,142 5,602 3,633 10,378
2 Released Capacity Revenue (149)(732)(475)(1,357)
3 Net UDC Costs (Credit)/Debit 993 4,870 3,158 9,021
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 4 of 55
Page 413
1.3 Panhandle Pipelines Refund Impact, net of interest
13. As outlined above, Enbridge Gas received a refund from Panhandle Pipelines
regarding over-recovery of costs of service of which $2.2 million, including interest,
pertained to UDC between 2020 and 2023. This amount has been credited to the
appropriate rate zones in alignment with the historic allocation of UDC costs for each
year.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 5 of 55
Page 414
ACCOUNT NO. 179-131 UPSTREAM TRANSPORTATION OPTIMIZATION
UNION RATE ZONES
1.The Upstream Transportation Optimization Deferral Account was approved by the
OEB in its EB-2011-0210 Decision to capture the variance between the ratepayers’
90% share of actual net revenues from optimization activities, and the amount
refunded to ratepayers in rates. The 2023 balance in this deferral account is a debit
from ratepayers of $8.087 million plus interest of $0.444 million for a total debit
from ratepayers of $8.531 million.
2.In setting rates for 2023, the OEB approved a forecast of optimization revenue of
$14.918 million. Of that amount, 90% or $13.426 million, was credited to
ratepayers in the OEB-approved 2023 rates.1 On an actual basis, consistent with
the method approved in its EB-2011-0210 Decision and Rate Order, Union credited
$15.280 million in rates to ratepayers during 2023, $1.854 million greater than the
OEB-approved amount of $13.426 million. The credit is due to actual sales service
volumes exceeding the forecast sales service volumes in rates. The main driver of
actual sales service volumes exceeding the forecasted amount is customer growth
since 2013.
3.The Company earned $7.991 million in net revenues from upstream transportation
optimization during 2023 in the Union Rate Zones. In accordance with the OEB-
approved sharing methodology, 90% of this net revenue, or $7.193 million, is to be
credited to customers. As stated above, $15.280 million has already been credited
through rates; therefore, the deferral balance is a debit from ratepayers of
$8.087 million ($15.280 million less $7.193 million).
4.The net revenue associated with upstream transportation optimization in the Union
Rate Zones is lower as compared to the net revenue associated with the Enbridge
1 Detailed schedule last filed at EB-2017-0087 (2018 Rates), Draft Rate Order, Working Papers, Schedule 14, p. 1. The credit of $13.426 million to Union rate zone in-franchise customers is maintained in the setting of rates for the 2019-2023 deferred rebasing period in accordance with the approved rate-setting mechanism.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 6 of 55
Page 415
Gas Distribution (EGD) Rate Zone primarily because of the portfolio of contracts
held by each rate zone. The EGD rate zone contracts used to transact exchanges
are more likely to be scheduled and provide greater revenue.
5.Exhibit E, Tab 1, Schedule 1, provides a summary of the calculation of the balance
in this deferral account. 2023 actual Upstream Transportation Optimization revenue
in the Union rate zones is lower than 2013 OEB-approved revenue primarily due to
the elimination of the TransCanada FT-RAM program ($5.800 million).
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 7 of 55
Page 416
ACCOUNT NO. 179-70 SHORT-TERM STORAGE AND OTHER BALANCING
SERVICES – UNION RATE ZONES
1. The Short-Term Storage and Other Balancing Services Deferral Account includes
revenues from C1 Off-Peak Storage, Gas Loans, Supplemental Balancing Services
and C1 Short-Term Firm Peak Storage. The deferral account compares the ratepayer
share (90%) of net revenue for Short-Term Storage and Other Balancing Services
with the amount credited to ratepayers in rates for Short-Term Storage and Other
Balancing Services. The net revenue for Short-Term Storage and Other Balancing
Services is determined by deducting the costs incurred to provide service from the
gross revenue. The balance in this deferral account is a debit from ratepayers of
$1.637 million, plus interest of $0.090 million for a total debit from ratepayers of
$1.727 million.
2.As shown in Table 3, the balance is calculated by comparing $2.914 million
(ratepayer 90% share of the actual 2023 Short-Term Storage and Other Balancing
Services net revenue of $3.237 million) to the net revenue included in Union rate
zone rates of $4.551 million.1 The details of the balance are found at Exhibit E, Tab 1,
Schedule 2.
Table 3
Deferral Summary: Short-term Storage and Other Storage Services
Line
No. Particulars ($000’s)
Actual
2023
1 Net Revenue 3,237
2 Ratepayer Portion (90%) 2,914
3 Approved in Rates 4,551
4 Deferral Balance Payable to/(Collectable from) Ratepayers (1,637)
1 EB-2011-0210, OEB Decision and Rate Order, January 17, 2013, p. 16.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 8 of 55
Page 417
3. Actual 2023 revenues from C1 Off-Peak Storage, Gas Loans and all other Balancing
services of $1.950 million were $0.550 million lower than the 2013 OEB-approved
forecast of $2.500 million.
4. The C1 Short-Term Firm Peak Storage revenues of $2.634 million were
$5.249 million lower than the 2013 Board-approved forecast of $7.883 million. Actual
Union rate zone utility storage requirements for 2023 were 9.4 PJ higher than the
2013 OEB-approved forecast, resulting in a decrease in the C1 Short-Term Firm
Peak Storage available for sale (from 11.3 PJ in 2013 OEB-approved to 1.9 PJ in
2023). Union rate zone customers received the value of storage directly through the
use of the storage space, rather than through the sale of short-term storage.
5.Year-over-year, actual utility storage requirements for 2023 were 1.6 PJ higher than
the requirement in 2022, resulting in a decrease in the C1 Short-Term Peak Storage
available for sale (from 3.5 PJ in 2022 to 1.9 PJ in 2023). This is a result of an
increase in the storage requirement for utility customers. The storage requirement for
the general service market was calculated using the OEB-approved aggregate
excess methodology. The storage requirement for the contract market was calculated
specifically for each customer using either the OEB-approved aggregate excess
methodology, the 15 times obligated Daily Contracted Quantity (DCQ) storage
methodology, or the 10 times Firm Contract Demand (CD) storage methodology (for
those customers who have elected the Customer Managed Service).2 Enbridge Gas
has included the calculation for utility storage space requirements and the
deliverability by rate class at Exhibit E, Tab 1, Schedule 2, Appendix A.3
6. The 2013 OEB-approved forecast implied an annual average value for C1 Short-
Term Firm Peak Storage of $0.70/GJ ($7.883 million/11.3 PJ), and the actual
average annual C1 Short-Term Firm Peak Storage value in 2023 was $1.41/GJ
2 EB-2016-0245, OEB Decision and Rate Order, Schedule 1, Settlement Proposal, p. 7.
3 EB-2021-0149, OEB Decision on Settlement Proposal, Schedule 1, Settlement Proposal, p.16.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 9 of 55
Page 418
($2.6 million/1.9 PJ). Please see Figure 1 for Short-Term Peak Storage values in US
dollars.
Figure 1 - Historical Short-Term Firm Peak Storage Values at Dawn 2015-2024
1. Non-Utility Storage Balances for 2023
7. In its EB-2011-0210 Decision, the OEB directed Union to file a report similar to that
ordered in EB-2011-0038 to monitor the inventory related to non-utility storage
operations. Exhibit E, Tab 1, Schedule 3 shows the non-utility inventory balances for
October and November of 2023 (for Union storage).
8. During the 2023 injection season, the non-utility storage balance peaked on
November 18, 2023 at 96.312% full with a balance of 124.6 PJ compared to available
space of 129.4 PJ. On October 31, 2023, the date to which the Company manages
its storage balance, the non-utility balance was 95.967% of available space. The
balance stayed below the total non-utility available space of 100% for the rest of
2023.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 10 of 55
Page 419
9. In EB-2011-0210, the OEB further ordered Union to file a calculation for a storage
encroachment payment from Union’s non-utility business to Union’s utility business, if
Union’s non-utility business encroached on Union’s utility space. There was no
encroachment of utility space in 2023 and therefore no calculation applies.
2. Sale of Non-Utility Storage Space
10. Enbridge Gas prioritizes the sale of Union utility storage ahead of the sale of its short-
term non-utility storage and allocates short-term peak storage margins between utility
and non-utility as directed by the OEB in EB-2011-0210.4 Margins from short-term
peak storage services are proportionately split between the utility and non-utility
customers based on the utility and non-utility share of the total quantity of short-term
peak storage sold each calendar year. Short-term peak sales include any sale of
storage space for a term of less than two storage years.
11. In 2023 Enbridge Gas sold a total of 3.2 PJ of short-term peak storage (Union).5 Of
this total, 1.9 PJ was excess utility space, calculated by deducting 98.1 PJ of in-
franchise utility requirement (as per the Gas Supply Plan) from the total 100 PJ of in-
franchise utility storage. Therefore, the excess short term peak sales of 1.4 PJ was
sold as non-utility space. Total revenue from the sale of C1 Short-Term Peak Storage
(Utility) in 2023 was $2.6 million. Details of the above sales are reflected in Exhibit E,
Tab 1, Schedule 4.
4 EB-2011-0210, OEB Decision and Order, October 24, 2012, pp. 116-117.
5 Total short-term peak storage sales of 3.2 PJ was derived from the sum of 1.36 PJ of non-utility short
term peak storage and 1.86 PJ of utility short term peak storage.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 11 of 55
Page 420
ACCOUNT NO. 179-133 NORMALIZED AVERAGE CONSUMPTION (NAC)
UNION RATE ZONES
1. The purpose of the NAC deferral account is to record the variance in delivery
revenue and storage revenue and costs resulting from the difference between the
target NAC included in OEB-approved rates and the actual NAC for general service
rate classes Rate M1, Rate M2, Rate 01 and Rate 10. As described in Union’s 2014
Deferral Account Disposition1 proceeding, including the revenue from storage rates
in the NAC deferral account requires storage-related costs associated with the
difference in target and actual NAC to also be included in the deferral account
balance.
2. For 2023, the balance in the NAC deferral account is a credit to ratepayers of $3.651
million plus interest of $0.201 million for a total credit to ratepayers of $3.852 million.
3. The NAC Deferral Account follows the same methodology agreed to by parties in
Union’s 2014-2018 Incentive Regulation (IR) Settlement Agreement2 and as
subsequently modified in Union’s 2015 Rates3 proceeding.
1. Target and Actual NAC
4. The 2023 target NAC used to calculate base rates for each rate class was approved
by the OEB in Enbridge Gas’s 2023 Rates4 proceeding. The 2021 actual NAC,
weather normalized using the 2023 weather normal, was used to determine the
2023 target NAC for each rate class to calculate base rates. Setting the 2023 target
NAC based on the 2021 actual NAC recognizes that over the two-year span to the
current year, any volumes saved and lost revenues due to DSM activities will be
captured by the variance between the target NAC and actual NAC. This is due to the
inclusion of the DSM saved volumes within the actual reported consumption.
1 EB-2015-0010.
2 EB-2013-0202.
3 EB-2014-0271.
4 EB-2022-0133.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 12 of 55
Page 421
5. The 2023 forecast usage used to calculate Y factor unit rates for each rate class was
approved by the OEB in Enbridge Gas’s 2023 Rates5 proceeding. The unit rates for
pass-through (Y factor) costs are derived based on OEB-approved cost allocation
and rate design methodologies and are passed through to customers at cost.
6. The 2023 actual NAC for each rate class is weather normalized using the 2023
weather normal, which is produced using the OEB-approved weather methodology
consisting of a 50:50 average of the 30-year average and the 20-year trend
estimates of annual heating degree-days.
7. Table 1 provides the 2023 target NAC and 2023 actual NAC by rate class for base
rates.
Table 1
2023 Target and Actual NAC - Base Rates
Line
No. Particulars (m3/customer)
Rate
01
Rate
10
Rate
M1
Rate
M2
(a)(b)(c)(d)
1 2023 Target NAC 2,731 149,709 2,631 148,143
2 2023 Actual NAC 2,709 140,937 2,680 149,349
3 Variance (Target - Actual NAC) 22 8,772 (50)(1,206)
8. Table 2 provides the 2023 target NAC and 2023 actual NAC by rate class for Y
factor rates.
Table 2
2023 Target and Actual NAC - Y Factor Rates
Line
No. Particulars (m3/customer)
Rate
01
Rate
10
Rate
M1
Rate
M2
(a)(b)(c)(d)
1 2023 Target NAC 2,763 163,047 2,572 156,375
2 2023 Actual NAC 2,709 140,937 2,680 149,349
3 Variance (Target - Actual NAC) 54 22,109 (108) 7,026
5 EB-2022-0133.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 13 of 55
Page 422
2. Delivery and Storage Revenues
9. The deferral account balance is calculated by multiplying the variance between the
weather normalized target NAC and the weather normalized actual NAC by the 2013
OEB-approved number of customers and the 2023 OEB-approved delivery and
storage rates for each general service rate class. A credit balance in the NAC
Deferral Account reflects that the actual NAC is greater than the target NAC, while a
debit balance in the NAC Deferral Account reflects that the actual NAC is less than
the target NAC.
10. Table 3 provides the NAC Deferral Account balances by rate class. The detailed
calculation of the NAC Deferral Account balance can be found at Exhibit E, Tab 1,
Schedule 5.
Table 3
2023 NAC Deferral Account
Line
No. Particulars ($000s)
Rate
01
Rate
10
Rate
M1
Rate
M2 Total
(a)(b)(c)(d)(e)
1 Delivery Revenue Balances 783 1,590 (3,869) 251 (1,246)
2 Storage Revenue Balances 340 703 (474)(77) 492
3 Storage Cost Balances (420)(186) (1,065) (1,226) (2,897)
4 Interest 39 116 (298) (58) (201)
5 Total NAC Deferral Balance 741 2,222 (5,706) (1,110) (3,852)
3. Deferral Account Impacts
11. For Rate M1, the 2023 actual NAC is higher than the target NAC used to derive
base rates by 50 m3/customer (Table 1, line 3, column (c)) and higher than the target
NAC used to derive Y factor rates by 108 m3/customer (Table 2, line 3, column (c)).
As shown in Table 3, this results in a delivery and storage revenue credit to
ratepayers of $4.343 million ($3.869 million and $0.474 million respectively). In
addition, the NAC volume variance decreases the Rate M1 storage requirement by
1.590 PJ. Accordingly, Enbridge Gas must refund an amount of $1.065 million
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 14 of 55
Page 423
(Table 3, line 3, column (c)) to Rate M1 customers to recognize the decreased Rate
M1 storage requirements.
12. For Rate M2, the 2023 actual NAC is higher than the target NAC used to derive
base rates by 1,206 m3/customer (Table 1, line 3, column (d)) and lower than the
target NAC used to derive Y factor rates by 7,026 m3/customer (Table 2, line 3,
column (d)). As shown in Table 3, this results in a delivery and storage revenue debit
to ratepayers of $0.174 million ($0.251 million debit and $0.077 million credit
respectively). In addition, the NAC volume variance decreases the Rate M2 storage
requirement by 1.830 PJ. Accordingly, Enbridge Gas must refund $1.226 million
(Table 3, line 3, column (d)) to Rate M2 customers to recognize the decreased Rate
M2 storage requirements.
13. For Rate 01, the 2023 actual NAC is lower than the target NAC used to derive base
rates by 22 m3/customer (Table 1, line 3, column (a)) and lower than the target NAC
used to derive Y factor rates by 54 m3/customer (Table 2, line 3, column (a)). As
shown in Table 3, this results in a delivery and storage revenue debit to ratepayers
of $1.123 million ($0.783 million and $0.340 million respectively). In addition, the
NAC volume variance decreases the Rate 01 storage requirement by 0.510 PJ.
Accordingly, Enbridge Gas must refund an amount of $0.420 million (Table 3, line 3,
column (a)) to Rate 01 customers to recognize the decreased Rate 01 storage
requirements.
14. For Rate 10, the 2023 actual NAC is lower than the target used to derive base rates
NAC by 8,772 m3/customer (Table 1, line 3, column (b)) and lower than the target
NAC used to derive Y factor rates by 22,109 m3/customer (Table 2, line 3, column
(b)). As shown in Table 3, this results in a delivery and storage revenue debit to
ratepayers of $2.292 million ($1.590 million and $0.703 million respectively). In
addition, the NAC volume variance decreases the Rate 10 storage requirement by
0.230 PJ. Accordingly, Enbridge Gas must refund an amount of $0.186 million
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 15 of 55
Page 424
(Table 3, line 3, column (b)) from Rate 10 customers to recognize the decreased
Rate 10 storage requirements.
4. Storage Costs
15. The storage costs recognize that variances between the 2023 target NAC and the
2013 OEB-approved NAC change the storage requirements for each general service
rate class. As OEB-approved storage rates are not updated during the IR term to
reflect changes in storage requirements due to NAC variances, Enbridge Gas must
capture the NAC-related change in storage costs in the NAC Deferral Account for
the Union rate zones, as per the OEB’s Decision in Union’s 2013 Deferrals
Disposition proceeding, “starting in 2014, the NAC Deferral Account, which replaces
the Average Use Per Customer Deferral Account, will include storage related
revenues and costs for general service rate classes.”6
16. To determine the change in storage requirements for each general service rate class
due to NAC variances, the Company calculated the NAC volume variance per
customer between its 2023/2024 Gas Supply Plan and the 2013 OEB-approved
volumes multiplied by the 2013 OEB-approved number of customers.
17. Using the OEB-approved aggregate excess methodology, Enbridge Gas calculated
the change in storage requirements for each of the general service rate classes due
to variances in NAC. The 2023/2024 Gas Supply Plan volumes represent the April 1,
2023 to March 31, 2024 period, which are used to determine the storage
requirements for general service rate classes effective November 1, 2023. These
general service rate class storage requirements are then used in the calculation of
the total in-franchise utility storage space requirement at November 1, 2023. The
difference between the total in-franchise utility storage requirement and the total
100 PJ of utility storage represents the excess utility storage capacity available for
sale (excess utility space) at November 1, 2023.
6 EB-2014-0145, OEB Decision and Order, pg. 9.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 16 of 55
Page 425
18. For Rate M1, the NAC volume variance between the 2023/2024 Gas Supply Plan
and the 2013 OEB-approved volumes was a decrease of 8.352 PJ. The majority of
the NAC volume variance decrease occurred in the winter months, which decreased
the Rate M1 storage requirement by 1.590 PJ. This resulted in decreased storage
costs of $1.065 million (Table 3, line 3, column (c)).
19. For Rate M2, the NAC volume variance between the 2023/2024 Gas Supply Plan
and the 2013 OEB-approved volumes was an increase of 2.839 PJ. The majority of
the NAC volume variance increase occurred in the summer months, which
decreased the Rate M2 storage requirement by 1.830 PJ and resulted in decreased
storage costs of $1.226 million (Table 3, line 3, column (d)).
20. For Rate 01, the NAC volume variance between the 2023/2024 Gas Supply Plan
and the 2013 OEB-approved volumes was a decrease of 0.538 PJ. The majority of
the NAC volume variance decrease occurred in the winter months, which decreased
the Rate 01 storage requirement by 0.510 PJ and decreased storage costs by
$0.420 million (Table 3, line 3, column (a)).
21. For Rate 10, the NAC volume variance between the 2023/2024 Gas Supply Plan
and the 2013 OEB-approved volumes was a decrease of 1.272 PJ. The majority of
the NAC volume variance decrease occurred in the winter months, which decreased
the Rate 10 storage requirement by 0.230 PJ and resulted in decreased storage
costs of $0.186 million (Table 3, line 3, column (b)).
22. Overall, the NAC volume variance between the 2023/2024 Gas Supply Plan and the
2013 OEB-approved volumes resulted in a decrease in general service storage
requirements of 4.160 PJ. Accordingly, Enbridge Gas has included a storage cost
credit of $2.897 million in the NAC Deferral Account. Please see Table 4 for a
summary of the change in general service storage requirements due to NAC volume
variances by rate class.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 17 of 55
Page 426
Table 4
Change in General Service Storage Requirements from 2013 OEB-approved
(based on weather normalized NAC)
PJ PJ
Rate M1 (1.590) Rate 01 (0.510)
Rate M2 (1.830) Rate 10 (0.230)
Total South (3.420) Total North (0.740)
23. The reduction in storage activity has decreased storage deliverability costs, the
commodity-related costs at Dawn and storage inventory carrying costs.
24. The 4.160 PJ reduction in general service storage requirements due to NAC volume
variances forms part of the 1.863 PJ of excess utility space available for sale for
winter 2023/2024. The revenue from the sale of the 1.863 PJ of excess utility space
is recorded in the Short-Term Storage and Other Balancing Deferral Account
(Account No. 179-70).
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 18 of 55
Page 427
DEFERRAL CLEARING VARIANCE ACCOUNT– UNION RATE ZONES
1. The purpose of the Deferral Clearing Variance Account (DCVA) is to capture the
differences between the forecast and actual volumes associated with the disposition
of deferral account balances to the Union rate zones. The intent of the variance
account is to minimize or eliminate the gains or losses to ratepayers and the
Company as a result of volume variances associated with the disposition of deferral
account balances.
2. The balance in this variance account is a debit from Union rate zones ratepayers of
$3.372 million, plus interest to December 31, 2023 of a $0.185 million, for a total
debit of $3.557 million. The balance includes the residual amounts not disposed of
from the following deferral dispositions: 2021 Earnings Sharing and Deferrals
(EB-2022-0110) cleared effective January 2023, and 2021 Federal Carbon Pricing
Program (EB-2022-0194) cleared effective April 2023. The total forecast disposition
balance of these combined was a debit of $42.083 million, total recoveries were a
credit of $38.711 million, resulting in a net residual debit balance of $3.372 million. A
summary is provided in Table 1.
Table 1
Deferral Summary: Deferral Clearing Variance Account
Line
No. Proceeding
Amount
($ millions)
1 2021 Earnings Sharing and Deferrals (EB-2022-0110) 41.679
2 2021 Federal Carbon Pricing Program (EB-2022-0194) 0.404
3 Subtotal – Approved for Disposition in 2023 42.083
4 Amounts disposed of in 2023 through one-time billing adjustments (38.711)
5 Residual balance to Deferral Clearing Variance Account 3.372
3. The residual balance reflects the outstanding amount resulting from the clearance of
deferral and variance accounts in the Union rate zone which occurred during 2023
and the inability to locate and dispose of the approved amounts to all intended
customers.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 19 of 55
Page 428
PARKWAY WEST PROJECT COSTS DEFERRAL ACCOUNT
UNION RATE ZONES
1. In its Parkway West Project (EB-2012-0433) Decision, the OEB approved the
establishment of the Parkway West Project Costs Deferral Account to track the
differences between the actual revenue requirement related to costs for the Parkway
West Project and the revenue requirement included in rates.
2. In the 2016 deferral account proceeding, the OEB noted that “all parties agreed that
the 2016 balance in the Parkway West Project Costs Account should be disposed of
only on an interim basis to allow the OEB to perform a prudence review of the capital
overspend prior to final disposition of the balance in the account.” This treatment
continued through to the 2021 deferral and variance account disposition proceeding.
However, as part of the 2022 deferral and variance account disposition proceeding,
clearance of the 2022 balance (and prior balances) was on a final basis. This
reflected that within the EB-2022-0200 (Enbridge Gas’s 2024 Rebasing Application)
approved Settlement Proposal, the actual capital spending and rate base amounts
through 2022 (including the Parkway West project) were agreed to and approved. As
a result, Enbridge Gas is seeking approval for the disposition of the Parkway West
Project Costs Deferral Account (179-136) in this proceeding on a final basis.
3. The balance in this deferral account is a credit to Union rate zones ratepayers of
$0.696 million plus interest of $0.049 million for a total credit balance of
$0.745 million. The balance of $0.696 million represents the difference between the
revenue requirement of $20.307 million included in 2023 rates (EB-2022-0133) and
the calculation of the actual revenue requirement for 2023 of $19.611 million as
shown in Table 1.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 20 of 55
Page 429
Col. 1 Col. 2 Col. 3
Line
No.Particulars ($000's)
2023 Board-
approved 2023 Actuals Difference
(a)(b) (c) = (b - a)
Rate Base Investment
1 Capital Expenditures - - -
2 Cumulative Capital Expenditures 233,147 232,432 (715)
3 Average Investment 188,678 187,433 (1,245)
Revenue Requirement Calculation:
Operating Expenses:
4 Operating and Maintenance Expenses 2,295 1,884 (411)
5 Depreciation Expense (1)5,532 5,505 (27)
6 Property Taxes 602 407 (196)
7 Total Operating Expenses 8,430 7,796 (634)
8 Required Return (2)10,678 10,608 (70)
9 Total Operating Expense and Return 19,108 18,404 (704)
Income Taxes:
10 Income Taxes - Equity Return (3)2,187 2,172 (15)
11 Income Taxes - Utility Timing Differences (4)(988) (965) 23
12 Total Income Taxes 1,199 1,207 8
13 Total Revenue Requirement 20,307 19,611 (696)
Notes:
(1) Depreciation expense at 2013 Board-approved depreciation rates.
(2)
$187.433 million * 64% * 3.82% = $4.582 million plus
$187.433 million * 36% * 8.93% = $6.026 million for a total of $10.608 million.
(3) Taxes related to the equity component of the return at a tax rate of 26.5%.
(4)
Table 1
2023 Parkway West Project Rate Base and Revenue Requirement
The required return assumes a capital structure of 64% long-term debt at 3.82% and 36%
common equity at the 2013 Board-approved return of 8.93%. The 2023 required return
calculation is as follows:
Taxes related to utility timing differences are negative as the capital cost allowance deduction in
arriving at taxable income exceeds the provision of book depreciation in the year.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 21 of 55
Page 430
1. Average Investment
4. The average investment decrease of $1.245 million from OEB-approved is primarily
due to the cumulative capital expenditures being $0.715 million lower than OEB-
approved capital expenditures.
2. Operating Expenses
5. Operating and maintenance expenses were $0.411 million below the costs included
in the 2023 OEB-approved rates. The decrease is a result of the continued absence
of a Long-term Service Agreement (LTSA) that was forecasted and included in 2023
OEB-approved rates but not incurred in actual O&M expense. The Company elected
not to enter an LTSA, that would have provided loss of critical unit coverage should
the Company experience operational issues with Parkway B, as with the
commissioning of Parkway D it was determined that it provided the required backup.
6. Property taxes were $0.196 million lower than costs included in 2023 OEB-approved
rates. The decrease is a result of the Municipal Property Assessment Corporation
(MPAC) deciding not to apply a Land Classification tax charge that was expected for
2019 and onwards.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 22 of 55
Page 431
BRANTFORD KIRKWALL/PARKWAY D PROJECT COSTS
UNION RATE ZONES
1. In its Brantford-Kirkwall/Parkway D (EB-2013-0074) Decision, the OEB approved the
establishment of the Brantford-Kirkwall/Parkway D Project Costs Deferral Account to
track the differences between the actual revenue requirement related to costs for the
Brantford-Kirkwall/Parkway D Project and the revenue requirement included in rates.
2. The balance in this deferral account is a credit to Union rate zone ratepayers of
$0.003 million plus interest of $0.0003 million for a total credit balance of
$0.003 million. The balance of $0.003 million represents the difference between the
revenue requirement of $15.506 million included in 2023 rates (EB-2022-0133) and
the calculation of the actual revenue requirement for 2023 of $15.503 million as
shown in Table 1.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 23 of 55
Page 432
Col. 1 Col. 2 Col. 3
Line
No. Particulars ($000's)
2023 Board-
approved
2023
Actuals Difference
(a)(b) (c) = (b - a)
Rate Base Investment
1 Capital Expenditures - - -
2 Cumulative Capital Expenditures 197,404 197,378 (26)
3 Average Investment 157,718 157,694 (24)
Revenue Requirement Calculation:
Operating Expenses:
4 Operating and Maintenance Expenses - - -
5 Depreciation Expense (1)4,995 4,995 (0)
6 Property Taxes 995 994 (1)
7 Total Operating Expenses 5,990 5,989 (1)
8 Required Return (2)8,926 8,925 (1)
9 Total Operating Expense and Return 14,916 14,914 (2)
Income Taxes:
10 Income Taxes - Equity Return (3)1,828 1,828 -
11 Income Taxes - Utility Timing Differences (4)(1,239) (1,239) -
12 Total Income Taxes 589 589 -
13 Total Revenue Requirement 15,506 15,503 (3)
Notes:
(1) Depreciation expense at 2013 Board-approved depreciation rates.
(2)
$157.694 million * 64% * 3.82% = $3.855 million plus
$157.694 million * 36% * 8.93% = $5.070 million for a total of $8.925 million.
(3) Taxes related to the equity component of the return at a tax rate of 26.5%.
(4)
Table 1
2023 Brantford-Kirkwall Pipeline/Parkway D Project Rate Base and Revenue
The required return assumes a capital structure of 64% long-term debt at 3.82% and 36% common equity
at the 2013 Board-approved return of 8.93%. The 2022 required return calculation is as follows:
Taxes related to utility timing differences are negative as the capital cost allowance deduction in arriving at
taxable income exceeds the provision of book depreciation in the year.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 24 of 55
Page 433
2023 UNACCOUNTED FOR GAS VOLUME DEFERRAL ACCOUNT
UNION RATE ZONES
1. The purpose of the Unaccounted for Gas Volume Deferral Account (UFGVDA) is to
capture the difference between the cost of Unaccounted for Gas (UFG) recovered
in rates, as previously approved by the OEB, and actual UFG costs incurred
annually.1 The balance recorded within the UFGVDA to be cleared to customers is
subject to a symmetrical dead-band of $5.0 million, with amounts within such dead-
band being recorded to Enbridge Gas’s account. This evidence provides details
regarding 2023 balances recorded in the UFGVDA.
2. In the Union Rate Zones, 2023 OEB-approved rates included $11.6 million in UFG
costs (based on forecasted throughput volumes). Based on 2023 actual throughput
volumes, Enbridge Gas recovered $16.4 million in UFG costs through rates. In
comparison, Enbridge Gas’s actual 2023 UFG costs were $20.3 million. The
variance between 2023 UFG costs recovered through rates and actual 2023 UFG
costs is $3.9 million, which is below the $5.0 million dead band established by the
OEB for the UFGVDA. As a result, there is no 2023 balance in the UFGVDA (see
Table 1 for detailed calculations).
1 Deferral Account No. 179-135.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 25 of 55
Page 434
Table 1
2023 Utility UFG Variances from OEB-Approved
Line Variance
No. Particulars ($Millions)
1 UFG Cost Included in Rates (1) (3) 11.6
2 Net Recovery Variance 4.8
3 Total UFG Collected in 2023 Rates (line 1 + line 2) (2) (3) 16.4
4 Total Utility UFG Actual Cost (2)(4) 20.3
5 Total Utility UFG Variance (line 3 - line 4) (3.9)
6 $5M UFG Symmetrical Dead-band 5.0
7 UFG Volume Deferral -
Notes:
(1) Board Approved throughput is 32,010 106m3
(2)Actual throughput is 45,242 106m3
(3) Board Approved UFG % is 0.219%
(4)Actual UFG % is 0.271%
3. Table 2 provides historical total UFG volumes (utility and non-utility) and UFG
volumes as a percentage of total throughput (UFG%) for the Union Rate Zones
from 2001 to 2023.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 26 of 55
Page 435
Table 2
Historical Total UFG Volumes for the Union Rate Zones (1)
Line
No. Calendar Year UFG Volumes (103 m3) UFG %
1 2001 184,102 0.673%
2 2002 109,542 0.344%
3 2003 108,819 0.356%
4 2004 176,650 0.554%
5 2005 169,540 0.507%
6 2006 154,015 0.516%
7 2007 203,713 0.609%
8 2008 143,880 0.411%
9 2009 201,845 0.637%
10 2010 67,283 0.192%
11 2011 35,668 0.105%
12 2012 68,690 0.210%
13 2013 113,997 0.320%
14 2014 97,109 0.318%
15 2015 54,408 0.174%
16 2016 131,588 0.427%
17 2017 108,901 0.342%
18 2018 136,447 0.379%
19 2019 137,652 0.376%
20 2020 74,120 0.208%
21 2021 252,582 0.663%
22 2022 250,692 0.592%
23 2023 122,613 0.271%
Note:
(1) Includes utility and non-utility volumes
4. Figure 1 compares historical UFG% for the Union Rate Zones from 2001 to 2023 to
the 2013 OEB-approved UFG%.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 27 of 55
Page 436
5. In the Settlement Proposal for the Company’s 2022 Deferral and Variance Account
and Earnings Sharing proceeding (EB-2023-0092)2, Enbridge Gas agreed to
address the following items in the current Application:
Detailed evidence will be filed about the items learned and future plans arising
from the ongoing review and investigation of UFG (see Exhibit I.Staff.6), including
(without limitation):
o the work completed by Enbridge Gas during 2023 and 2024 and the resulting
observations and learnings,
o the impact on UFG from “no bill” customers / volumes that are later billed,
o the role, if any, played by line pack in transmission and other high pressure
systems in the incidence and determination of UFG, and
o the Company’s investigation plan for assessing fugitive emissions.3
6. Accordingly, to support the relief sought by Enbridge Gas and to satisfy
commitments previously made regarding UFG volumes, Enbridge Gas is providing
additional detail surrounding recent learnings and observations made regarding
UFG, the impact of No-Bills and transmission and high-pressure system Linepack
2 EB-2023-0092, Decision on Settlement Proposal and Rate Order, February 6, 2024, p.4.
3 As agreed in the EB-2022-0200 Settlement Proposal, Exhibit O1, Tab 1, Schedule 1, June 28, 2023,
pp. 36-37.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 28 of 55
Page 437
on UFG, and the Company’s Fugitive Emissions Measurement Project. The
additional detail broadly applies to all rate zones unless otherwise indicated and is
set out at Exhibit D, Tab 1.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 29 of 55
Page 438
UNACCOUNTED FOR GAS (UFG) PRICE VARIANCE ACCOUNT
UNION RATE ZONES
1. The UFG Price Variance Account captures the variance between the average
monthly price of the Company’s purchases for the Union rate zones and the
applicable OEB-approved reference price, applied to the Company’s actual UFG
volumes for the Union rate zones. Price variances are initially recorded in the PGVA
deferral accounts and the portion of the price variances associated with UFG
volumes is transferred from the PGVA to the UFG Price Variance Account. This
transfer ensures that costs are borne by the appropriate group of ratepayers,
consistent with the UFG cost allocation.
2. During 2023, the Company purchased 25,047 103m3 of gas supply in Union rate
zones related to actual UFG volumes on behalf of ratepayers. The actual UFG
purchases exclude the actual UFG collected from ratepayers who provide UFG
in kind as part of customer supplied fuel (CSF).
3. The average actual cost of the UFG purchases in 2023 is $25.12/103m3 lower than
the OEB-approved reference prices included in rates based on the Union South rate
zone gas portfolio cost of $179.35/103m3. The result is a $0.63 million balance to be
refunded to ratepayers, as shown in Table 1. Table 2 provides the detailed
calculation supporting the price variance of $25.12/103m3.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 30 of 55
Page 439
Table 1
Calculation of 2023 UFG Price Variance
Line UFG
Volumes
No. Particulars (103m3)
1 Experienced Regulated UFG (1) 110,438
2 UFG Collected through CSF 85,390
3 UFG Volumes – Company Supplied (2) 25,047
Deferral
Calculation
4 UFG Volumes (103m3) – Company Supplied (2) 25,047
5 Price Variance ($/103m3) (3) $(25.12)
6 Variance Account Balance ($ millions) $(0.63)
Notes
(1) Converted using the following heat values (39.12 Jan-Mar) (39.17 Apr – Dec).
(2) UFG Volumes represent gas supply related to actual UFG volumes on behalf of ratepayers
who do not provide UFG in kind as part of CSF.
(3) See Table 2 for the price variance calculation.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 31 of 55
Page 440
LineNo. Particulars Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average Price1Board Approved Reference Price ($ / 103m3)$260.27 $260.27 $260.27 $156.99 $156.99 $156.99 $142.15 $142.15 $142.15 $158.01 $158.01 $158.01 $179.352 Actual Purchase ($)$84,284,125 $53,867,441 $43,742,400 $29,850,340 $33,298,860 $32,522,592 $26,349,940 $41,063,934 $40,695,471 $25,203,931 $40,760,374 $43,793,9873Purchase Volumes (103m3)323,298 282,273 281,039 225,234 261,806 273,778 192,873 315,344 302,906 165,919 250,496 293,2224Average Purchase Cost (Union South)($ / 103m3) (1)$260.70 $190.83 $155.65 $132.53 $127.19 $118.79 $136.62 $130.22 $134.35 $151.91 $162.72 $149.35 $154.245Union South Price Variance ($ / 103m3) (2)$0.44 ($69.43) ($104.62) ($24.46) ($29.80) ($38.20) ($5.53) ($11.93) ($7.80) ($6.11) $4.71 ($8.66) ($25.12)Notes(1) Line 2 / Line 3(2) Line 4 - Line 1Table 2Calculation of 2023 Union South Price VarainceFiled: 2024-05-31 EB-2024-0125 Exhibit E Tab 1 Page 32 of 55Page 441
LOBO C COMPRESSOR/HAMILTON MILTON PIPELINE PROJECT COSTS
DEFERRAL ACCOUNT – UNION RATE ZONES
1. In its Dawn Parkway 2016 Expansion (EB-2014-0261) Decision, the OEB approved
the establishment of the Lobo C Compressor/Hamilton-Milton Pipeline Project Costs
Deferral Account to track the differences between the actual revenue requirement
related to costs for the Project and the revenue requirement included in rates.
2. The balance in this deferral account is a debit from Union Rate Zone ratepayers of
$0.268 million plus interest of $0.010 million for a total debit balance of
$0.278 million. The balance of $0.268 million represents the difference between the
revenue requirement of $26.537 million included in 2023 rates (EB-2022-0133) and
the calculation of the actual revenue requirement for 2023 of $26.805 million as
shown in Table 1.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 33 of 55
Page 442
Col. 1Col. 2Col. 3
Line
No.Particulars ($000's)
2023 Board-
approved 2023 Actuals Difference
(a)(b) (c) = (b - a)
Rate Base Investment
1 Capital Expenditures - - -
2 Cumulative Capital Expenditures 347,980 347,062 (918)
3 Average Investment 290,349 289,578 (771)
Revenue Requirement Calculation:
Operating Expenses:
4 Operating and Maintenance Expenses 898 1,378 480
5 Depreciation Expense (1)8,261 8,214 (47)
6 Property Taxes 1,258 1,123 (135)
7 Total Operating Expenses 10,417 10,715 298
8 Required Return (2)15,578 15,536 (42)
9 Total Operating Expense and Return 25,995 26,252 257
Income Taxes:
10 Income Taxes - Equity Return (3)3,370 3,356 (14)
11 Income Taxes - Utility Timing Differences (4)(2,828) (2,803) 25
12 Total Income Taxes 542 553 11
13 Total Revenue Requirement 26,537 26,805 268
Notes:
(1) Depreciation expense at 2013 Board-approved depreciation rates.
(2)
$289.578 million * 64% * 3.36% = $6.227 million plus
$289.578 million * 36% * 8.93% = $9.309 million for a total of $15,536 million.
(3) Taxes related to the equity component of the return at a tax rate of 26.5%.
(4)
Table 1
2023 Lobo C Compressor/Hamilton-Milton Pipeline Project Rate Base and Revenue Requirement
The required return assumes a capital structure of 64% long-term debt at 3.36% and 36% common
equity at the 2013 Board-approved return of 8.93%. The 2023 required return calculation is as
follows:
Taxes related to utility timing differences are negative as the capital cost allowance deduction in
arriving at taxable income exceeds the provision of book depreciation in the year.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 34 of 55
Page 443
1. Average Investment
3. The average investment decrease of $0.771 million from OEB-approved is due to
the cumulative capital expenditures being $0.918 million lower than OEB-approved
capital expenditures.
2. Operating Expenses
4. Operating and maintenance expenses were $0.480 million higher than the costs
included in 2023 OEB-approved rates. The increase is a result of higher general
maintenance and repairs to equipment and assets incurred in 2023, not in the
original forecast.
5. Property taxes were $0.135 million lower than costs included in 2023 OEB-approved
rates. The decrease is a result of continued Provincial tax reductions for business
education tax rates on commercial, industrial, and pipeline tax in 2023.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 35 of 55
Page 444
UNAUTHORIZED OVERRUN NON-COMPLIANCE DEFERRAL ACCOUNT
UNION RATE ZONES
1.In Union’s 2016 Rates Decision and Order (EB-2015-0116), the OEB ordered the
Company to establish the Unauthorized Overrun Non-Compliance Deferral Account
to record any unauthorized overrun non-compliance charges incurred by interruptible
distribution customers for not complying with a distribution interruption.
2.In 2023, there were 5 interruption events called in the Union North rate zone for a
total of 23 days and 1 interruption event called in the Union South rate zone for a
total of 5 days. Two (2) customers were not compliant with interruptions in 2023,
resulting in unauthorized overrun non-compliance charges and a credit to ratepayers
of $0.0455 million, plus interest of $0.0043 million for a total credit to ratepayers of
$0.0498 million.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 36 of 55
Page 445
LOBO D/BRIGHT C/DAWN H COMPRESSOR PROJECT COSTS
UNION RATE ZONES
1. In its EB-2015-0116 Decision, the OEB approved the establishment of the Lobo
D/Bright C/Dawn H Compressor Project Costs Deferral Account to track the
differences between the actual revenue requirement related to costs for the
Lobo D/Bright C/Dawn H Compressor Project and the revenue requirement included
in rates.
2. The balance in this deferral account is a debit to Union Rate Zone ratepayers of
$0.066 million plus interest of ($0.039) million, for a total debit balance of $0.027
million. The principal balance of $0.027 million includes a debit of $1.437 million
which represents the difference between the revenue requirement of $47.480 million
included in 2023 rates (EB-2022-0133) and the calculation of the actual revenue
requirement for 2023 of $48.917 million as shown in Table 1.
3. The principal balance also includes a $1.371 million credit, which relates to the 2023
revenue generated from the sale of surplus Dawn Parkway system capacity of
30,393 GJ/day associated with the Lobo D/Bright C/Dawn H Compressor Project. In
accordance with the 2018 Disposition of Deferral and Variance Account Balances
and Utility Earnings proceeding (EB-2019-0105) approved Settlement Proposal, the
surplus capacity is deemed to be sold long-term and the revenue credit for the 2023
year is calculated based on the M12 Dawn-Parkway rate of $3.760/GJ approved in
the EB-2022-0133 Rate Order, dated November 3, 2022. A schedule supporting the
2023 revenue calculation is provided at Exhibit E, Tab 1, Schedule 6.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 37 of 55
Page 446
Col. 1 Col. 2 Col. 3
Line
No. Particulars ($000's)
2023 Board-
approved
2023
Actuals Difference
(a)(b)(c)= (b - a)
Rate Base Investment
1 Capital Expenditures - - -
2 Cumulative Capital Expenditures 622,500 620,050 (2,450)
3 Average Investment 517,534 517,226 (308)
Revenue Requirement Calculation:
Operating Expenses:
4 Operating and Maintenance Expenses 1,832 3,008 1,176
5 Depreciation Expense (1)17,418 17,437 19
6 Property Taxes 1,089 1,087 (2)
7 Total Operating Expenses 20,340 21,532 1,192
8 Required Return (2)27,535 27,519 (16)
9 Total Operating Expense and Return 47,875 49,051 1,176
Income Taxes:
10 Income Taxes - Equity Return (3)5,998 5,995 (3)
11 Income Taxes - Utility Timing Differences (4)(6,392) (6,130) 262
12 Total Income Taxes (394) (135)259
13 Total Revenue Requirement 47,480 48,917 1,437
Notes:
(1) Depreciation expense at 2013 Board-approved depreciation rates.
(2)
$517.226 million * 64% * 3.29% = $10.891 million plus
$517.226 million * 36% * 8.93% = $16.628 million for a total of $27.519 million.
(3) Taxes related to the equity component of the return at a tax rate of 26.5%.
(4)
Table 1
2023 Dawn H/Lobo D/Bright C Compressor Project Rate Base And Revenue Requirement
The required return assumes a capital structure of 64% long-term debt at 3.29% and 36% common
equity at the 2013 Board-approved return of 8.93%. The 2023 required return calculation is as
Taxes related to utility timing differences are negative as the capital cost allowance deduction in
arriving at taxable income exceeds the provision of book depreciation in the year.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 38 of 55
Page 447
1. Average Investment
4. The average investment decrease of $0.308 million from OEB-approved is due to
the cumulative capital expenditures being $2.450 million lower than OEB-approved.
2. Operating Expenses
5. Operating and maintenance expenses were $1.176 million higher than the costs
included in 2023 OEB-approved rates. The increase is a result of higher
salaries/wages, higher contractor and general maintenance costs than budgeted due
to a Gas Generator repair at Dawn H, and higher utility costs at Bright C and Lobo
D. Table 2 shows the breakdown and comparison of actual 2023 operating and
maintenance costs versus OEB-approved.
Table 2
2023 Dawn H/Lobo D/Bright C Compressor Operating And Maintenance Expenses
Col. 1 Col. 2 Col. 3
Line 2023 Board- 2023
No. Particulars ($Millions) approved Actuals Difference
(a) (b) (c)= (b - a)
1 Salaries & Wages 906 1,297 391
2 HR Costs 408 581 174
3 Fleet Costs 136 194 59
4 Training, Travel and PE 69 6 (63)
5 Other O&M (Contract Services) 172 709 537
6 Company Used Fuel 75 - (75)
7 Utility Costs 66 220 154
8 Total Capital Expenditures 1,832 3,008 1,176
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 39 of 55
Page 448
BURLINGTON OAKVILLE PROJECT COSTS DEFERRAL ACCOUNT
UNION RATE ZONES
1. In its EB-2015-0116 Decision, the OEB approved the establishment of the Burlington
Oakville Project Costs Deferral Account to track the differences between the actual
revenue requirement related to costs for the Project and the revenue requirement
included in rates.
2. The balance in this deferral account is a credit to Union rate zone ratepayers of
$0.043 million plus interest of $0.003 million for a total credit balance of
$0.046 million. The balance of $0.046 million represents the difference between the
revenue requirement of $5.840 million included in 2023 rates (EB-2022-0133) and
the calculation of the actual revenue requirement for 2023 of $5.797 million as
shown in Table 1. The small decline in the actual revenue requirement results from
minor underages in the capital cost and operating costs of the project.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 40 of 55
Page 449
Col. 1 Col. 2 Col. 3
Line
No.Particulars ($000's)
2023
Board-
approved
2023
Actuals Difference
(a)(b)(c) = (b - a)
Rate Base Investment
1 Capital Expenditures - - -
2 Cumulative Capital Expenditures 83,349 83,262 (87)
3 Average Investment 71,351 71,235 (116)
Revenue Requirement Calculation:
Operating Expenses:
4 Operating and Maintenance Expenses 18 - (18)
5 Depreciation Expense (1)1,732 1,737 5
6 Property Taxes 140 120 (20)
7 Total Operating Expenses 1,889 1,857 (32)
8 Required Return (2)3,828 3,822 (6)
9 Total Operating Expense and Return 5,717 5,679 (38)
Income Taxes:
10 Income Taxes - Equity Return (3)828 826 (2)
11 Income Taxes - Utility Timing Differences (4)(705) (708) (3)
12 Total Income Taxes 123 117 (6)
13 Total Revenue Requirement 5,840 5,797 (43)
Notes:
(1) Depreciation expense at 2013 Board-approved depreciation rates.
(2)
$71.235 million * 64% * 3.36% = $1.532 million plus
$71.235 million * 36% * 8.93% = $2.290 million for a total of $3.822 million.
(3) Taxes related to the equity component of the return at a tax rate of 26.5%.
(4)Taxes related to utility timing differences are negative as the capital cost allowance deduction in arriving at
taxable income exceeds the provision of book depreciation in the year.
The required return assumes a capital structure of 64% long-term debt at 3.36% and 36% common equity at
the 2013 Board-approved return of 8.93%. The 2023 required return calculation is as follows:
Table 1
2023 Burlington Oakville Pipeline Project Rate Base and Revenue Requirement
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 41 of 55
Page 450
2023 ONTARIO ENERGY BOARD COST ASSESSMENT VARIANCE ACCOUNT
UNION RATE ZONES
1. The purpose of the 2023 Ontario Energy Board Cost Assessment Variance
Account (OEBCAVA) was to record any material variances between the OEB costs
assessed to Enbridge Gas (relevant to the Union rate zones) through application of
the revised Cost Assessment Model (CAM), which became effective April 1, 2016,
and the OEB costs which were included in Union rate zones rates, which were
determined through application of the prior Cost Assessment Model. The scope of
the account is consistent with prior OEBCAVAs. However, in accordance with the
EB-2020-0134 OEB-approved Settlement Proposal1, in EGI’s 2019 Earnings
Sharing and Deferral Disposition proceeding, the base OEB costs assumed to be
included in rates have been escalated to the reflect the growth in the amount
recovered through rates, which results from annual price cap adjustments and
customer growth. The OEBCAVA was originally approved for establishment by an
OEB letter dated February 9, 2016, entitled: Revisions to the Ontario Energy Board
Cost Assessment Model.
2. The amount recorded within the 2023 OEBCAVA is $1.630 million, plus interest of
$0.131 million for a total debit balance of $1.761 million. This amount reflects the
variance between OEB costs assessed to Enbridge Gas (relevant to Union rate
zones) in each quarter of fiscal 2023, utilizing the revised CAM, and Union’s
average quarterly OEB cost assessment under the prior CAM, escalated in
accordance with the EB-2020-0134 OEB-approved Settlement Proposal.
3. In order to calculate the amount to be recovered through the 2023 Union rate
zones OEBCAVA, the Company first needed to apportion the actual 2023 OEB
assessed costs between the legacy rate zones. Commencing with the OEB’s 2019
/ 2020 fiscal first quarter assessment (for the period April 1, 2019 through June 30,
1 EB-2020-0134, Decision on Settlement Proposal, January 25, 2021, pp. 5-6.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 42 of 55
Page 451
2019), and continuing since, EGI has been receiving one consolidated quarterly bill
for the amalgamated utility. To apportion the quarterly assessments received in
2023 between rate zones, the assessments were prorated based on the total
invoices received by each legacy utility for the OEB’s 2018 / 2019 fiscal year (for
the period April 1, 2018 through March 31, 2019), the final year for which the OEB
issued invoices to each legacy utility. Table 1 below shows the proration of the
OEB’s 2018 / 2019 fiscal year assessments between each legacy utility / rate zone
(59.76% EGD rate zone, 40.24% Union rate zones). Table 2 shows the
apportionment of EGI’s 2023 assessed costs to the Union rate zones, and the
calculation of the amount recorded in the 2023 Union rate zones OEBCAVA.
4. To calculate the amount for recovery through the 2023 Union rate zones
OEBCAVA, the Company also needed to establish the base comparator, reflecting
the OEB costs included in Union rate zones rates, determined through application
of the prior Cost Assessment Model. In accordance with the EB-2020-0134 OEB-
approved Settlement Proposal, and methodology subsequently approved through
the EB-2021-0149, 2020 Earnings Sharing and Deferral and Variance Account
Clearance proceeding, the amount reflected in rates is to be increased, or
escalated, to reflect the growth in the amount recovered as a result of annual price
cap adjustments and customer growth. To establish the 2023 base comparator,
the Company escalated the 2022 quarterly comparator of $0.762 million by the
sum of the 2023 Price Cap Index (PCI) of 3.60%, and the Union rate zones ICM
threshold calculation Growth Factor (g) of 1.39%. The 2023 PCI was approved as
part of Enbridge Gas’s 2023 Rate Application, EB-2022-0133. The 2023 ICM
threshold calculation Growth Factor was not filed as part of the 2023 Rate
Application, as no ICM funding was requested, but has been calculated using the
same methodology as the 2022 ICM threshold calculation Growth Factor, which
was approved as part of Enbridge Gas’s 2022 Rate Application, EB-2021-
0147/0148. The escalation resulted in a 2023 quarterly comparator of $0.800
million ($0.762 million * (1 + (3.60% + 1.39%))). As noted above, Table 2 shows
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 43 of 55
Page 452
the apportionment of Enbridge Gas’s actual 2023 assessed costs to the Union rate
zones, and the calculation of the amount recorded in the 2023 Union rate zones
OEBCAVA utilizing a base comparator of $0.800 million.
5. Within this proceeding, the Company is requesting clearance of the principal and
interest balances recorded in the 2023 OEBCAVA, in the amount of $1.630 million
and $0.131 million respectively, as shown in Exhibit C, Tab 1, Schedule 1.
Table 2
Calculation of 2023 UGL RZ OEBCAVA
Line
No. Period
EGI
Assessment
UGL Rate
Zone Share
(40.24%)
Average Cost
assessment
Comparator
Variance to
UGL Rate
Zone
OEBCAVA
1 Jan. 1 to Mar. 31, 2023 2,738,849.00 1,102,112.84 800,283.18 301,829.66
2 Apr. 1 to Jun. 30, 2023 3,141,892.00 1,264,297.34 800,283.18 464,014.16
3 Jul. 1 to Sep. 30, 2023 3,062,860.00 1,232,494.86 800,283.18 432,211.68
4 Oct. 1 to Dec. 31, 2023 3,062,860.00 1,232,494.86 800,283.18 432,211.68
5 12,006,461.00 4,831,399.90 3,201,132.72 1,630,267.18
Table 1
2018/2019 OEB Cost Assessments
Line
No.
Period
EGD UGL Total
1 Apr. 1 to Jun. 30, 2018 1,467,963 988,479 2,456,442
2 Jul. 1 to Sep. 30, 2018 1,356,860 913,873 2,270,733
3 Oct. 1 to Dec. 31, 2018 1,356,860 913,873 2,270,733
4 Jan. 1 to Mar. 31, 2019 1,356,860 913,873 2,270,733
5 5,538,543 3,730,098 9,268,641
6 Percentage of Total 59.76% 40.24% 100.00%
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 44 of 55
Page 453
2023 BASE SERVICE NORTH T-SERVICE TRANSCANADA CAPACITY DEFERRAL
ACCOUNT – UNION RATE ZONE
1.In the EB-2015-0181 decision, the OEB approved a new optional Union North T-
service Transportation from Dawn to allow T-service customers in the Union North
East Zone with access to Dawn-based supply. To facilitate this service, Enbridge
Gas was required to contract for 15-year transportation capacity with TransCanada
from Parkway to the Union CDA, Union NCDA and Union EDA. The approved rates
for the service are equal to the EGI C1 rate from Dawn to Parkway and the
TransCanada Firm Transportation (FT) toll to Delivery Area.
2.The purpose of the North T-service TransCanada Capacity Deferral Account is to
record the difference between the costs for the capacity from Parkway to the
northern Delivery Area as part of the Base Service offering of the North T-Service
Transportation from Dawn and the demand revenues collected from the North T-
Service customers.
3.The total cost Enbridge Gas paid for the contracted TransCanada capacity in 2023
was $2.136 million. On an actual basis, the Company collected $2.057 million
demand revenues from the North T-service customers. As a result, the balance in
the 2023 North T-service TransCanada Capacity Deferral Account is a collection
from ratepayers of $0.079 million plus interest of $0.006 million and the balance will
be cleared amongst all North T-service from Dawn customers. The variance is
driven by a net reduction of 480 GJ per day of contracted capacity by North T-
service customers.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 45 of 55
Page 454
PANHANDLE REINFORCEMENT PROJECT COSTS DEFERRAL ACCOUNT
UNION RATE ZONES
1. In its Panhandle Reinforcement Project (EB-2016-0186) Decision, the OEB
approved the establishment of the Panhandle Reinforcement Project Costs Deferral
Account to track the differences between the actual net revenue requirement related
to costs for the Project and the net revenue requirement included in rates.
2. The balance in this deferral account is a credit to Union rate zone ratepayers of
$1.884 million plus interest of $0.146 million for a total credit balance of
$2.030 million. The balance of $1.884 million represents the difference between the
net revenue requirement of $9.576 million included in 2023 rates (EB-2022-0133)
and the calculation of the actual net revenue requirement for 2023 of
$7.692 million as shown in Table 1.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 46 of 55
Page 455
Col. 1 Col. 2 Col. 3
Line
No.Particulars ($000's)
2023 Board-
approved 2023 Actuals Difference
(a)(b) (c)= (b - a)
Rate Base Investment
1 Capital Expenditures - - -
2 Cumulative Capital Expenditures 232,844 228,574 (4,270)
3 Average Investment 204,069 200,152 (3,917)
Revenue Requirement Calculation:
Operating Expenses:
4 Operating and Maintenance Expenses 17 -(17)
5 Depreciation Expense (1)4,944 4,788 (156)
6 Property Taxes 1,885 1,677 (209)
7 Total Operating Expenses 6,846 6,464 (382)
8 Required Return (2)10,857 10,649 (208)
9 Total Operating Expense and Return 17,703 17,113 (590)
Income Taxes:
10 Income Taxes - Equity Return (3)2,365 2,320 (45)
11 Income Taxes - Utility Timing Differences (4)(2,598) (2,599) (1)
12 Total Income Taxes (233) (279) (46)
13 Total Revenue Requirement 17,470 16,834 (636)
14 Incremental Project Revenue 7,895 9,142 1,247
15 Net Revenue Requirement 9,576 7,692 (1,884)
Notes:
(1) Depreciation expense at 2013 Board-approved depreciation rates.
(2)
$200.152 million * 64% * 3.29% = $4.214 million plus
$200.152 million * 36% * 8.93% = $6.434 million for a total of $10.649 million.
(3) Taxes related to the equity component of the return at a tax rate of 26.5%.
(4)
Table 1
2023 Panhandle Reinforcement Project Rate Base and Revenue Requirement
The required return assumes a capital structure of 64% long-term debt at 3.29% and 36% common
equity at the 2013 Board-approved return of 8.93%. The 2023 required return calculation is as
follows:
Taxes related to utility timing differences are negative as the capital cost allowance deduction in
arriving at taxable income exceeds the provision of book depreciation in the year.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 47 of 55
Page 456
1. Average Investment
3. The average investment decrease of $3.917 million from OEB-approved is due to
the cumulative capital expenditures being $4.270 million lower than OEB-approved
capital expenditures.
2. Operating Expenses
4. Property taxes were $0.209 million lower than costs included in 2023 OEB-approved
rates. The decrease is a result of Provincial tax reductions for business education
tax rates on commercial, industrial, and pipeline tax in 2023.
3. Required Return
5. The decrease in the required return of $0.208 million is the result of a lower average
rate base.
4. Incremental Project Revenue
6. The actual incremental revenue of $9.142 million reflects the impacts of customer
growth and expansion by existing customers in the Panhandle market, and is
$1.247 million higher than the forecast incremental revenue included in 2023 Rates.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 48 of 55
Page 457
2023 PENSION AND OPEB FORECAST ACCRUAL VS ACTUAL CASH PAYMENT
DIFFERENTIAL VARIANCE ACCOUNT – UNION RATE ZONES
1. In its EB-2015-0040 report to all regulated entities, dated September 14, 2017, titled
“Regulatory Treatment of Pension and Other Post-employment Benefits (OPEB)
Costs”, the OEB ordered the establishment of the deferral account, effective
January 1, 2018, to be used by utilities that are approved to recover their pension
and OPEB costs on an accrual basis1. The Company recovers its pension and
OPEB costs on an accrual basis.
2. The purpose of the Pension and OPEB Forecast Accrual vs Actual Cash Payment
Differential Variance Account is to track the differences between forecast accrual
pension and OPEB amounts recovered in rates, and the actual cash payments
made for both pension and OPEB, on a go-forward basis from the date the account
was established.
3. In 2023, the accrual pension and OPEB amount recovered in rates for the Union rate
zones was $47.4 million and the actual cash payments made for both pension and
OPEB were $6.7 million, resulting in an annual $40.8 million credit variance. The
variance carried forward from 2022 is a $102.0 million credit variance, resulting in a
cumulative $142.7 million credit variance through 2023.
4. In accordance with the OEB’s Report (EB-2015-0040), when the cumulative
forecasted accrual amount recovered in rates exceeds the cumulative actual cash
payments, an asymmetrical carrying charge, to be returned to ratepayers, should be
accrued based on the opening monthly difference between amount recovered in
rates and actual cash payments. The balance in the account for 2023 is an interest
1 EB-2015-0040, Regulatory Treatment of Pension and Other Post-employment Benefits (OPEB) Costs,
September 14, 2017, p.2.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 49 of 55
Page 458
credit to ratepayers of $6.2 million to December 31, 20232. Table 1 sets out the
detailed calculation of the forecast accrual versus actual cash payments, and
associated interest.
2 Interest is as of December 31, 2023, as interest on this account is calculated on a cumulative account
balance basis.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 50 of 55
Page 459
LineNo.Particulars ($000’s)22-Dec 23-Jan 23-Feb 23-Mar 23-Apr 23-May 23-Jun 23-Jul 23-Aug 23-Sep 23-Oct 23-Nov 23-Dec Total1Forecast accrual amounts3,951 3,951 3,951 3,951 3,951 3,951 3,951 3,951 3,951 3,951 3,951 3,951 47,4162Actual cash payments 403 333 1,291 289 270 1,032 231 248 1,072 226 254 1,010 6,6603Monthly variance-3,548 -3,618 -2,660 -3,663 -3,682 -2,919 -3,721 -3,703 -2,879 -3,725 -3,697 -2,941 -40,7564Cumulative variance -101,953 -105,501 -109,119 -111,779 -115,442 -119,123 -122,042 -125,763 -129,466 -132,345 -136,070 -139,767 -142,7095OEB prescribed CWIP rate 5.01% 5.01% 5.01% 5.01% 5.01% 5.01% 5.01% 5.01% 5.01% 5.48% 5.48% 5.48%6Asymmetrical interest-0.426 -0.440 -0.456 -0.467 -0.482 -0.497 -0.510 -0.525 -0.541 -0.604 -0.621 -0.638 -6.207Table 1Details Of 2023 Interest Calculated on Forecast Accruals vs Actual Cash Payments in Pension and OPEB Variance Account (No. 179-157)Filed: 2024-05-31 EB-2024-0125 Exhibit E Tab 1 Page 51 of 55Page 460
INCREMENTAL CAPITAL MODULE DEFERRAL ACCOUNT –
UNION RATE ZONES
1.The Incremental Capital Module Deferral Account (ICMDA) records the difference
between the actual revenue requirement for approved ICM projects, and the
revenues collected through ICM rates approved by the OEB on a project-by-project
basis.
2. In the EB-2022-0200 Phase 1 Decision on Settlement Proposal dated August 17,
2023, parties agreed to the clearance of deferral and variance accounts as proposed
by Enbridge Gas including ICMDA balances. The balance approved at the time was
comprised of actual & forecast amounts. Enbridge Gas is seeking final disposition of
the remaining balance in the ICM Deferral Account in this proceeding representative
of the variance between the forecast balance approved in the OEB approved Interim
Rate Order dated April 11, 2024, and the final actual balances as calculated through
December 31, 2023.
3. The balance in this deferral account is a credit to the UGL Rate Zone of $0.384
million plus interest of $0.504 million for a total credit balance of $0.888 million. The
balance of $0.384 million represents the difference between the credit balance
approved for disposition in the Interim Rate Order, of $26.396 million, and the
calculation of the final Union Rate Zone ICMDA credit balance of $26.779 million, as
shown in Table 1.
4. The principal variance of $0.384 million for the Union Rate Zone projects is the result
of a reduction in the actual revenue requirement of $0.9 million, partially offset by
$0.5 million less revenue collected in rates compared to forecast.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 52 of 55
Page 461
5.The interest variance of $0.504 is primarily due to the timing of the clearance of
deferral and variance accounts. An anticipated January 1, 2024, clearance date was
reflected in the forecast interest balance approved as part of the EB-2022-0200
Interim Rate Order, whereas the approved clearance date was May 1, 2024,
resulting in an additional 4 months of interest to be applied to the ICMDA balance of
$26.779 million.
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 53 of 55
Page 462
LineNo. ($000's)(a) (b) (c) (d) (e) (f) (g) (h) (i)Principal Interest Total Principal Interest Total Principal Interest TotalUGL Rate Zone1. Kingsville Transmission Reinforcement Project(14,100.0) (1,141.6) (15,241.6) (14,301.1) (1,410.4) (15,711.5) (201.1) (268.8) (469.9) 2 Windsor Line Replacement Project(8,100.0) (655.8) (8,755.8) (8,438.6) (832.2) (9,270.8) (338.6) (176.4) (515.0) 3 London Lines Replacement Project(4,195.9) (339.7) (4,535.6) (4,040.0) (398.4) (4,438.4) 155.9 (58.7) 97.2 4Total UGL Rate Zone APCDA(26,395.9) (2,137.1) (28,533.0) (26,779.7) (2,641.1) (29,420.7) (383.7) (504.0) (887.7) Notes:(1)(2) Reflects 2019 through 2023 actuals.(3) Represent variances between amounts approved for disposition in the Interim Rate Order and the final cumulative balances based on actuals.Table 1Summary of Incremental Capital Module Deferral AccountAmounts Requested for Clearance in 2023 ESM ProceedingEB-2022-0200 Rate Order, Working Papers, Schedule 27, pages 1 & 2; approved in Interim Rate Order dated April 11, 2024.(EB-2022-0200)1Final Cumulative Balances2 Amounts Proposed for Disposition(2023 ESM and Deferral Disposition)3Actual & ForecastBalances Approved for DispositionFiled: 2024-05-31 EB-2024-0125 Exhibit E Tab 1 Page 54 of 55Page 463
ACCOUNTS WITH A ZERO BALANCE
UNION RATE ZONES
1. The following 2023 accounts for the Union rate zones have no balance, and are
therefore not requested for clearance to customers:
Spot Gas Variance Account
Unbundled Services Unauthorized Storage Overrun Deferral Account
Gas Distribution Access Rule (GDAR) Costs Deferral Account
Conservation Demand Management Deferral Account
Sudbury Replacement Project Costs Deferral Account
Parkway Obligation Rate Variance Account
Unaccounted for Gas Volume Variance Account
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Page 55 of 55
Page 464
Col. 1 Col. 2 Col. 3
Line 2013 Board 2022 Actual 2023 Actual
No.Particulars Approved Total Total
($000's)($000's)($000's)
1 Base Exchange Revenue (9,118.0)(8,609.9)(7,991.8)
2 FT RAM Exchange Revenue (5,800.0)
3 Total Exchange Revenue (14,918.0)(8,609.9)(7,991.8)
4 Exchange Revenue Subject to Deferral (14,918.0)(8,609.9)(7,991.8)
5 Ratepayer portion - 90% (13,426.2)(7,748.9)(7,192.6)
6 10% Union Incentive Payment (861.0)(799.2)
7 Less: Gas Supply Optimization Margin in Rates 13,426.2 16,648.7 15,279.8
8 2023 Deferral Account Balance receivable from Ratepayers - 8,899.7 8,087.2
Breakdown of Upstream Transportation Optimization Deferral Account - Union Rate Zones
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Schedule 1 Page 1 of 1
Page 465
Col .1 Col. 2 Col. 3
Line Board-Approved Actual Actual
No.Particulars ($000's)2013 2022 2023
Revenue1C1 Off-Peak Storage 500 138 1,046
2 Supplemental Balancing Services 2,000 1,053 905
3 Gas Loans (1)(1)
4 LBA 0 0
5 2,500 1,189 1,950
6 C1 ST Firm Peak Storage 7,883 2,108 2,634
7 Total Revenue (1)10,383 3,297 4,583
Costs
8 O&M (2)3,810 1,172 627
9 UFG (3)316 1,521 448
10 Compressor Fuel (4)1,201 487 271
11 Total Costs 5,327 3,180 1,346
12 Net Revenue (line 7 - 11)5,056 117 3,237
13 Less Shareholder Portion (10%)505 12 324
14 Ratepayer Portion 4,551 105 2,914
15 Approved in Rates 4,551 4,551 4,551
16 Deferral balance payable to / (collectable from) ratepayers (0)(4,446)(1,637)
Notes:
(1) Based on short-term storage services provided(2) Revenue Requirement on 11.3 PJ's of board approved excess in-franchise storage capacity
(3) Based on short-term storage volumes in proportion to total volumes(4) Based on short-term storage activity in proportion to total actual storage activity
Breakdown Of Short Term Storage Deferral Account (STSDA) - Union Rate Zones
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Schedule 2 Page 1 of 1
Page 466
Storage Storage
Line Space (2)Deliverability (2)
No. Particulars (PJ)(GJ/d)
(a)(b)
Union North Rate Zone
1 Rate 01 12.0 221,290
2 Rate 10 2.8 63,618
3 Rate 20 2.3 36,813
4 Rate 25 - -
5 Rate 100 0.1 1,189
6 Total Union North Rate Zone 17.2 322,911
Union South Rate Zone
7 Rate M1 40.6 973,899
8 Rate M2 10.7 312,539
9 Rate M4 3.0 171,205
10 Rate M5 0.0 286
11 Rate M7 2.2 66,050
12 Rate M9 0.3 9,286
13 Rate M10 0.0 142
14 Rate T1 1.4 40,244
15 Rate T2 9.9 197,492
16 Rate T3 3.3 69,712
17 Total Union South Rate Zone 71.4 1,840,855
Ex-Franchise
18 Excess Utility Storage 1.9 (3)22,355
19 Rate C1 - -
20 Rate M12 - -
21 Rate M13 - -
22 Rate M16 - -
23 Total Ex-Franchise 1.9 22,355
24 System Integrity Space 9.5 -
25 Total Union Rate Zone 100.0 2,186,121
EGD Rate Zone
26 Rate 1 61.2 1,202,465
27 Rate 6 58.7 958,188
28 Rate 9 - -
29 Rate 100 - -
30 Rate 110 2.2 5,052
31 Rate 115 0.5 2,004
32 Rate 125 - -
33 Rate 135 - -
34 Rate 145 0.3 -
35 Rate 170 0.8 -
36 Rate 200 2.0 20,259
37 Total EGD Rate Zone 125.8 2,187,969
38 Total Enbridge Gas (line 25 + line 37)225.8 4,374,090
Notes:
(1) Allocation to rate classes using Board-approved cost allocation methodologies.
(2) Union Rate Zone storage space based on actual W23/24 usage and storage deliverability
based on forecast W23/24 requirements. EGD Rate Zone storage space and deliverability
based on 2023 Gas Supply plan.
(3) Exhibit E, Tab 1, page 8
Enbridge Gas Inc.
2023 Storage Space & Deliverability
2023 (1)
Filed: 2024-05-31
EB-2024-0125
Exhibit E
Tab 1
Schedule 2
Appendix A
Page 1 of 1
Page 467
Line No.Date Entitlement Balance % Full Date Entitlement Balance % Full
(PJ)(PJ)(%)(PJ)(PJ)(%)
1 1-Oct-23 129.4 118.3 91.5%1-Nov-23 129.4 124.3 96.1%2 2-Oct-23 129.4 118.5 91.6%2-Nov-23 129.4 124.4 96.2%3 3-Oct-23 129.4 118.8 91.8%3-Nov-23 129.4 124.6 96.3%4 4-Oct-23 129.4 119.2 92.1%4-Nov-23 129.4 124.5 96.2%
5 5-Oct-23 129.4 119.5 92.4%5-Nov-23 129.4 124.4 96.1%6 6-Oct-23 129.4 119.8 92.6%6-Nov-23 129.4 124.4 96.2%
7 7-Oct-23 129.4 120.1 92.9%7-Nov-23 129.4 124.3 96.1%8 8-Oct-23 129.4 120.5 93.2%8-Nov-23 129.4 124.3 96.1%9 9-Oct-23 129.4 120.9 93.4%9-Nov-23 129.4 124.4 96.2%10 10-Oct-23 129.4 121.1 93.6%10-Nov-23 129.4 124.3 96.1%11 11-Oct-23 129.4 121.2 93.7%11-Nov-23 129.4 124.0 95.9%12 12-Oct-23 129.4 121.5 93.9%12-Nov-23 129.4 123.6 95.5%13 13-Oct-23 129.4 121.6 94.0%13-Nov-23 129.4 123.4 95.4%
14 14-Oct-23 129.4 121.9 94.2%14-Nov-23 129.4 123.4 95.4%15 15-Oct-23 129.4 122.1 94.4%15-Nov-23 129.4 123.6 95.5%16 16-Oct-23 129.4 122.2 94.5%16-Nov-23 129.4 124.2 96.0%17 17-Oct-23 129.4 122.4 94.6%17-Nov-23 129.4 124.4 96.1%18 18-Oct-23 129.4 122.8 94.9%18-Nov-23 129.4 124.6 96.3%19 19-Oct-23 129.4 123.1 95.1%19-Nov-23 129.4 124.4 96.1%20 20-Oct-23 129.4 123.2 95.3%20-Nov-23 129.4 124.0 95.8%
21 21-Oct-23 129.4 123.7 95.6%21-Nov-23 129.4 123.9 95.8%22 22-Oct-23 129.4 124.0 95.8%22-Nov-23 129.4 123.9 95.7%
23 23-Oct-23 129.4 124.2 96.0%23-Nov-23 129.4 123.6 95.5%24 24-Oct-23 129.4 124.5 96.2%24-Nov-23 129.4 123.0 95.1%25 25-Oct-23 129.4 124.7 96.4%25-Nov-23 129.4 122.4 94.6%26 26-Oct-23 129.4 124.9 96.5%26-Nov-23 129.4 122.1 94.4%27 27-Oct-23 129.4 125.2 96.7%27-Nov-23 129.4 121.2 93.7%28 28-Oct-23 129.4 125.4 96.9%28-Nov-23 129.4 119.0 92.0%29 29-Oct-23 129.4 125.4 96.9%29-Nov-23 129.4 117.7 91.0%
30 30-Oct-23 129.4 124.9 96.6%30-Nov-23 129.4 117.0 90.5%31 31-Oct-23 129.4 124.2 96.0%
Union Gas LimitedSummary of Non-Utility Storage Balances
Filed: 2024-05-31 EB-2024-0125
Exhibit E
Tab 1
Schedule 3
Page 1 of 1
Page 468
Revenue
Utility Short Term from Short
Line Storage Peak Storage Term Peak
No. Particulars Space Sold Storage
(PJ)(PJ)($ millions)
1 Net Revenues from Short Term Peak Storage 4.6
2 Total Short Term Peak Storage Sales 3.2
3 Storage Space reserved for Utility 100.0
4 Utility Space Requirement 98.1
5 Excess Utility Storage Space (line 3 - line 4)1.9
6 Total Utility Short Term Peak Storage Sales (line 5)1.9
7 Total Non Utility Short Term Peak Storage Sales 1.4
8 Short Term Peak Storage Net Revenues - Utility (line 6 / line 2 * line 1)2.6
9 Short Term Peak Storage Net Revenues - Non Utility (line 7 / line 2 * line 1)1.9
Union Rate Zone
Southern Operations Area
Allocation of Short Term Peak Storage Revenues Between Utility and Non Utility
Filed: 2024-05-31 EB-2024-0125 Exhibit E Tab 1 Schedule 4 Page 1 of 1
Page 469
LineNet AccountNo.Particulars Rate 01Rate 10Rate M1Rate M2Balance(a)(b)(c)(d)(e)Base Rates1 2023 Target NAC: m³2,730.6 149,709.1 2,630.8 148,142.6 2 2023 Actual NAC: m³2,709.1 140,937.4 2,680.5 149,348.5 3 Actual change in NAC: m³ (line 1 - 2) 21.5 8,771.7 (49.7) (1,206.0) Y Factor Rates4 2023 Target NAC: m³ 2,763.3 163,046.7 2,572.3 156,374.8 5 2023 Actual NAC: m³2,709.1 140,937.4 2,680.5 149,348.5 6 Actual change in NAC: m³ (line 4 - 5) 54.2 22,109.3 (108.2) 7,026.3 7 2013 Board-approved number of Customers at December323,287.0 2,064.0 1,067,757.0 6,778.0 1,399,886.0 Base Rates8Annual Volume Impact (103m3) (1)6,797 17,925 (52,502) (9,071) (36,851) 9 2023 Net Annual Average Delivery Rate ($/m3) (2)$0.100$0.066$0.043$0.04210 2023 Net Annual Average Storage Rate ($/m3) (3)$0.050$0.039$0.009$0.00911 Delivery Rate Annual Balance Amount ($000)(4)$680$1,178($2,280)($382)($805)12 Storage Rate Annual Balance Amount ($000) (4)$340$702($474)($77)$491Y Factor Rates13Annual Volume Impact (103m3) (1)17,258 45,299 (114,669) 46,775 (5,337) 14 2023 Net Annual Average Delivery Rate ($/m3) (2)$0.006$0.009$0.014$0.01415 2023 Net Annual Average Storage Rate ($/m3) (3)$0.000$0.000$0.000$0.00016 Delivery Rate Annual Balance Amount ($000)(4)$103$412($1,588)$633($441)17 Storage Rate Annual Balance Amount ($000) (4)$0$1$0$0$1Total Annual Balance Amounts ($000)18 Total Delivery Rate Annual Balance Amount (line 11+16)$783$1,590($3,869)$251($1,245.5)19 Total Storage Rate Annual Balance Amount (line 12+17)$340$703($474)($77)$491.620 Storage Cost Annual Balance Amount ($000) ($420)($186)($1,065)($1,226)($2,897)21 Interest ($000)(5)$39$116($298)($58)($201)22 Total Deferral Account Amounts ($000) (line 18+19+20+21)$741$2,222($5,706)($1,110)($3,852.1)Notes:(1)(2)(3)(4)(5)The annual volume is obtained from a monthly calculation of approved customers and the monthly usage variance.The Net Annual Average Delivery Rate is the volume-weighted average of Board-approved monthly unit rates in effectThe Net Annual Average Storage Rate is the volume-weighted average of Board-approved monthly unit rates in effectThe annual revenue is obtained from a monthly calculation of volumes (lines 8 and 13) and the monthly unit delivery and storage rates (lines 9, 10, 14 and 15).Interest is calculated on the monthly opening balance in the deferral account in accordance with the methodology approved by the Board in EB-2006-0117. Interest is calculated to Dec 31, 2024.Union Rate ZonesCalculation of Balances by Rate Class in the NAC Deferral Account (No. 179-133) - Base Rates and Y-FactorFiled: 2024-05-31 EB-2024-0125 Exhibit E Tab 1 Schedule 5 Page 1 of 1Page 470
Line No. ParticularsVolume (TJ/d) (1)Actual Revenue ($000's) (2)Project Surplus Allocation (%)Revenue Allocation ($000's) (a)(b)(c)(d) = (b) x (c)1 January30 114100%1142 February30 114100%1143 March30 114100%1144 April30 114100%1145 May30 114100%1146 June30 114100%1147 July30 114100%1148 August30 114100%1149 September30 114100%11410 October30 114100%11411 November30 114100%11412 December30 114100%11413 Total1,3711,371Notes(1)Capacity of 30,393 GJ/d assumed to be sold long term.(2)Sold at the Dawn to Parkway M12 Rate of $3.760 $/GJCalculation of 2023 Transportation Revenues on the Lobo D/Bright C/Dawn H Compressor Project Cost Deferral Account Union Rate ZonesFiled: 2024-05-31 EB-2024-0125 Exhibit E Tab 1 Schedule 6 Page 1 of 1Page 471
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 1
Page 1 of 9
ALLOCATION AND DISPOSITION OF
2023 DEFERRAL AND VARIANCE ACCOUNT BALANCES
1. The purpose of this evidence is to address the allocation and disposition of 2023
deferral and variance account balances identified at Exhibit C, Tab 1, Schedule 1.
2. Enbridge Gas proposes to dispose of the approved 2023 deferral and variance
account balances with the first QRAM application following the OEB’s approval, as
early as January 1, 2025.
3. This exhibit of evidence is organized as follows:
1. Allocation of Deferral and Variance Accounts
1.1 EGI Accounts
1.2 EGD Rate Zone Accounts
1.3 Union Rate Zones’ Accounts
2. Disposition of Deferral and Variance Accounts
3. General Service Bill Impacts
1. Allocation of Deferral and Variance Accounts
1. In accordance with the OEB’s EB-2017-0306/EB-2017-0307 Decision and Order
(MAADs Decision), the OEB approved new Enbridge Gas deferral and variance
accounts that apply to both the EGD rate zone and Union rate zones effective
January 1, 2019. The applicability of other deferral and variance accounts that were
approved to continue during the deferred rebasing period is for either the EGD rate
zone or the Union rate zones.
Page 472
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 1
Page 2 of 9
1.1. EGI Accounts
2. The OEB previously approved0F
1 the following deferral and variance accounts for
Enbridge Gas that are applicable to both the EGD and Union rate zones:
Earnings Sharing Mechanism Deferral Account (ESMDA),
Tax Variance Deferral Account (TVDA),
IRP Operating Costs Deferral Account,
IRP Capital Costs Deferral Account,
Green Button Initiative Deferral Account,
Cloud Computing Implementation Costs Deferral Account,
Getting Ontario Connected Act Variance Account (GOCA) and,
Expansion of Natural Gas Distribution System Variance Account
(ENGDSVA),
Accounting Policy Changes Deferral Account (APCDA), and
Impacts Arising from the COVID-19 Emergency Deferral Account (IACEDA).
3. Enbridge Gas is proposing to dispose of the 2023 balance in the TVDA, IRP
Operating Costs Deferral Account, GOCA, and APCDA as part of this application.
There is no balance for the ESMDA, IRP Capital Costs Deferral Account, Green
Button Initiative Deferral Account, Cloud Computing Implementation Costs Deferral
Account, ENGDSVA, and IACEDA as shown at Exhibit C, Tab 1, Schedule 1.
4. The 2023 TVDA balance, including interest, is a credit of $31.198 million. Consistent
with the methodology approved by the OEB in previous years, Enbridge Gas has
split the credit balance of $31.198 million between the EGD and Union rate zones in
1 EB-2017-0306/EB-2017-0307 Decision and Order established the APCDA, ESMDA and TVDA. The
ENGDSVA was established in accordance with Section 4 of Ontario Regulation 24/19. The IRP Operating
Costs Deferral Account and the IRP Capital Costs Deferral Account were established in accordance with
the EB-2020-0091 Decision and Order. The Green Button Initiative Deferral Account was established in
accordance with the EB-2020-0183 Accounting Order. The Cloud Computing Implementation Costs
Deferral Account was established in accordance with the 003-2023 Accounting Order. The GOCA was
established in accordance with the EB-2023-0143 Decision and Order. The IACEDA was established in
accordance with the EB-2020-0133 Report of the OEB.
Page 473
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EB-2024-0125
Exhibit F
Tab 1
Page 3 of 9
proportion to the 2018 actual rate base for each rate zone.1F
2 Splitting the $31.198
million TVDA credit balance in proportion to 2018 actual rate base results in a credit
of $16.469 million being allocated to the EGD rate zone and a credit of $14.729
million being allocated to the Union rate zones. The details of the split to rate zones
is provided at Exhibit F, Tab 1, Schedule 1.
5. The 2023 IRP Operating Cost Deferral Account balance, including interest, is a debit
of $3.328 million. Included in the balance is a $0.301 million2F
3 debit, including
interest, for IRP project costs related to an IRP Plan to defer a pipeline
reinforcement project in the Kingston, Ontario area.3F
4 Enbridge Gas has directly
assigned $0.301 million to the Union North rate zone. Consistent with the
methodology approved in previous years, Enbridge Gas has split the remaining debit
balance of $3.027 million, which excludes IRP project costs, between the EGD and
Union rate zones in proportion to the 2018 actual rate base for each rate zone.4F
5
Splitting the $3.027 million debit balance in proportion to 2018 actual rate base
results in a debit of $1.598 million being allocated to the EGD rate zone and a debit
of $1.429 million being allocated to the Union rate zones. The total debit balance to
be allocated to the Union rate zones is $1.730 million5F
6. The details of the split to rate
zones is provided at Exhibit F, Tab 1, Schedule 1.
6. Enbridge Gas proposes to allocate the $0.301 million balance related to Kingston
IRP project costs to Union North rate classes in proportion to the system peak and
average day demands, excluding the demands of customers who are served by sole
use mains. The proposed allocation methodology is consistent with the allocation of
2 EB-2020-0134 Decision and Order, May 6, 2021, page 16.
3 $0.279 million of IRP project costs plus $0.022 million of interest.
4The balance of the IRP Operating Costs Deferral Account, including a description of the IRP project
costs is described at Exhibit C, Tab 1.
5 In the EB-2022-0110 Decision and Order, November 8, 2022, the OEB accepted the settlement
proposal where parties agreed to the allocation of the IRP Operating Costs Deferral Account balance
where there are no associated IRP project costs.
6 $0.301 million direct assignment for IRP project costs plus $1.429 allocation of remaining balance.
Page 474
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EB-2024-0125
Exhibit F
Tab 1
Page 4 of 9
joint use mains in the Union North rate zone in Union’s 2013 OEB-approved Cost
Allocation Study.6F
7 The proposed allocation methodology is the same as the
methodology that would be used for the assets that would be installed under the
pipeline reinforcement project that was deferred as a result of the Kingston IRP
project.
7. The 2023 GOCA balance, including interest, is a debit of $33.639 million. As
described in Exhibit C, Tab 1, Enbridge Gas proposes to split the balance in the
GOCA variance account to rate zones in proportion to the number of locates
completed within each rate zone during 2023. Accordingly, splitting the debit balance
of $33.639 million in proportion to the 2023 number of locates results in a debit of
$20.858 million allocated to the EGD rate zone and a debit of $2.456 million and
$10.325 million allocated to the Union North and Union South rate zones,
respectively. The calculation of the deferral split to rate zones is provided at Exhibit
F, Tab 1, Schedule 1.
8. The GOCA variance account captures the incremental costs of locates resulting
from the enactment of Bill 93. Therefore, Enbridge Gas proposes to allocate the
balance in each rate zone to rate classes in proportion to the allocation of locate
costs included in current approved rates.
9. For the EGD rate zone, Enbridge Gas proposes to allocate the balance in the GOCA
variance account related to the EGD rate zone to rate classes in proportion to the
allocation of System Operation Distribution Operating Expenses approved by the
OEB in EGD’s 2018 Cost Allocation Study8. For both the Union North and Union
South rate zones, Enbridge Gas proposes to allocate the balance in the GOCA
variance account related to the Union North and Union South rate zones to rate
7 EB-2010-0210.
8 System Operation Distribution Operating Expenses are classified at EB-2017-0086, Exhibit G2, Tab 4,
Schedule 3, p. 2, line 2.3 and allocated at EB-2017-0086, Exhibit G2, Tab 5, Schedule 3, lines 4.1-4.4
and line 4.7.
Page 475
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EB-2024-0125
Exhibit F
Tab 1
Page 5 of 9
classes in proportion to the allocation of Mains and Services Distribution Operating
O&M expenses by rate zone approved by the OEB in Union’s 2013 Cost Allocation
Study9.
10. The 2023 APCDA balance, including interest, is a debit of $5.547 million, consisting
of a credit of $7.713 million for the EGD rate zone and a debit of $13.260 million for
the Union rate zones as provided at Exhibit C, Tab 1, Schedule 2. The proposed
cost allocation methodologies are consistent with the methodologies approved by
the OEB in the calculation of the APCDA component by rate zone of Rider D as part
of Enbridge Gas’s Phase 1 rate order in EB-2022-0200. A description of the
proposed methodology by rate zone is provided below.
11. Enbridge Gas proposes to allocate the APCDA deferral balance for capitalization vs.
expense, interest during construction and overhead capitalization related to the EGD
rate zone to EGD rate classes in proportion to the OEB approved rate base in EGD’s
2018 cost allocation study. This proposed allocation recognizes the accounting
policy changes are primarily related to capital and rate base assets.
12. Enbridge Gas proposes to allocate the APDCA deferral balance for amortized gas
supply storage & transportation costs related to the EGD rate zone to EGD rate
classes in proportion to the storage deliverability requirements from the OEB
approved 2018 cost allocation study for the EGD rate zone. This proposed allocation
approach is consistent with the allocation of similar storage costs in the 2018 cost
allocation study.
13. Enbridge Gas proposes to allocate the APCDA deferral balance for capitalization vs.
expense, interest during construction, depreciation expense and overhead
capitalization related to the Union rate zones to Union rate classes in proportion to
9 Union North Rate Zone as per EB-2011-0210, Exhibit G3, Tab 5, Schedule 1, pg. 21, Mains & Services
line within Distribution Operating O&M expenses. Union South Rate Zone as per EB-2011-0210, Exhibit
G3, Tab 5, Schedule 1, pg. 16-17. Mains & Services line within Distribution Operating O&M expenses.
Page 476
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 1
Page 6 of 9
the OEB approved rate base in Union’s 2013 cost allocation study. This proposed
allocation recognizes the accounting policy changes are primarily related to capital
and rate base assets.
14. Enbridge Gas has allocated the split balance of the TVDA, and the remaining
balance of the IRP Operating Cost Deferral Account to rate classes in each rate
zone in proportion to 2018 rate base for the EGD rate zone and 2013 rate base for
the Union rate zones, consistent with the methodology approved in previous years.
The rate base allocation for each rate zone is taken from the last fully allocated cost
study prepared for each rate zone. The allocation to EGD rate classes is provided at
Exhibit F, Tab 2, Schedule 3. The allocation to Union rate classes is provided at
Exhibit F, Tab 3, Schedule 2.
1.2 EGD Rate Zone Accounts
15. The 2023 deferral and variance account balances to be cleared to the EGD rate
zone are provided at Exhibit F, Tab 2, Schedule 2, including the EGD rate zone
allocation of the EGI accounts.
16. The 2023 RNGISVA balance, including interest, is a credit of $0.360 million. In its
Decision and Order in EB-2017-031910, the OEB determined that RNG injection
services is a distribution activity and that it was appropriate to clear the balance in
the account to distribution customers and not RNG producers. Accordingly, Enbridge
Gas proposes to allocate the balance in the RNGISVA to EGD rate zone rate
classes in proportion to 2023 actual throughput volumes.
17. The 2023 Incremental Capital Module deferral account (ICMDA) for the EGD rate
zone, including interest, is a credit of $5.141 million. Enbridge Gas proposes to
allocate the ICMDA balance for the EGD rate zone to rate classes in proportion to
the total design day demands utilizing high pressure mains greater than 4 inches in
10 EB-2017-0319, Decision and Order dated October 18, 2018, pp. 21-22.
Page 477
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 1
Page 7 of 9
diameter from the OEB approved 2018 Cost Allocation Study. The proposed cost
allocation methodology is consistent with the methodology approved by the OEB in
the calculation of the EGD rate zone ICMDA component of Rider D as part of
Enbridge Gas’s Phase 1 rate order in EB-2022-0200.
18. The remaining 2023 EGD rate zone deferral and variance account balances are
allocated to the customer classes using the same methodologies that the OEB
approved in previous years.
19. The allocation of account balances to EGD rate classes based on cost drivers for
each type of account is provided at Exhibit F, Tab 2, Schedule 3. A summary of the
allocation of account balances by rate class and type of service is provided at
Exhibit F, Tab 2, Schedule 4.
1.3 Union Rate Zones’ Accounts
20. The 2023 deferral and variance account balances to be cleared to the Union rate
zones are provided at Exhibit F, Tab 3, Schedule 2, including the Union rate zones
allocation of the EGI accounts.
21. The 2023 Incremental Capital Module deferral account (“ICMDA”) for the Union rate
zone, including interest, is a credit of $0.888 million. As shown in Table 1 of Exhibit
E, Tab 1, Page 3, the deferral balance consists of a credit of $0.470 million related to
the Kingsville Transmission Reinforcement Project, a credit of $0.515 million related
to the Windsor Line Replacement Project, and a debit of $0.097 million related to the
London Lines Replacement Project. Enbridge Gas proposes to allocate the ICMDA
credit balance related to the Kingsville Transmission Reinforcement Project to Union
South in-franchise rate classes in proportion to 2019 Other Transmission design day
demands. Enbridge Gas proposes to allocate the ICMDA credit balance related to
the Windsor Line Replacement Project to Union South in-franchise rate classes in
proportion to 2020 Distribution design day demands. Enbridge Gas proposes to
allocate the ICMDA debit balance related to the London Lines Replacement Project
Page 478
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 1
Page 8 of 9
to Union South in-franchise rate classes in proportion to 2021 Union South in-
franchise Other Transmission design day demands. The proposed cost allocation
methodologies are consistent with the methodologies approved by the OEB in the
calculation of Union rate zones ICMDA component of Rider D as part of Enbridge
Gas’s Phase 1 rate order in EB-2022-0200.
22. The remaining 2023 Union rate zones’ deferral and variance account balances are
allocated to the customer classes using the same methodologies that the OEB
approved in previous years.
23. The allocation of account balances to Union South and Union North rate classes is
provided at Exhibit F, Tab 3, Schedule 3.
2. Disposition of Deferral and Variance Accounts
24. Enbridge Gas proposes to dispose of the approved 2023 deferral and variance
account balances with the first QRAM application following the OEB’s approval, as
early as January 1, 2025.
25. Enbridge Gas proposes to dispose of the 2023 deferral and variance account
balances as a one-time billing adjustment. The billing adjustment will appear as a
separate line item on customers’ bills, the earliest being January 2025. The one-time
billing adjustment will be derived for each customer by applying the disposition unit
rates to each customer’s actual consumption volume or contract demand, as
applicable, for the period January 1, 2023 to December 31, 2023.
26. The unit rates for disposition by rate class and service type are provided at Exhibit F,
Tab 2, Schedule 1 and Schedule 5 for the EGD rate zone. The unit rates for
disposition for the Union rate zones, including a summary of the balances to be
Page 479
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EB-2024-0125
Exhibit F
Tab 1
Page 9 of 9
disposed of to ex-franchise rate classes are provided at Exhibit F, Tab 3,
Schedule 4.
3. General Service Bill Impacts
27. For a Rate 1 sales service and western t-service customer in the EGD rate zone with
annual consumption of 2,400 m3, the one-time billing adjustment credit is $5.12.7F
11
28. For a Rate M1 sales service residential customer in Union South with annual
consumption of 2,200 m3, the one-time billing adjustment charge is $9.51. For a
Rate M1 bundled direct purchase (DP) residential customer, the one-time billing
adjustment charge is $1.60.
29. For a Rate 01 sales service and bundled DP residential customer in Union North
West with annual consumption of 2,200 m3, the one-time billing adjustment credit is
$0.13.
30. For a Rate 01 sales service and bundled DP residential customer in Union North
East with annual consumption of 2,200 m3, the one-time billing adjustment charge is
$0.47.
31. Bill impacts of the proposed disposition are provided at Exhibit F, Tab 2, Schedule 6
for the EGD rate zone and Exhibit F, Tab 3, Schedule 5 for the Union rate zones.
11 In addition to the EGD rate zone 2023 Deferral bill impacts, the allocation of Union rate zone deferrals
to Rate M12 results in a bill credit of approximately $0.14 to a typical Rate 1 residential customer in the
EGD rate zone.
Page 480
Line Allocation
No. Particulars ($ millions)to Rate Zone Principal Interest Total
(a)(b)(c)(d) = (b+c)
2023 Tax Variance Deferral Account
Allocation -2018 Rate Base (1) (2)
1 EGD rate zone 6,729 (15.036) (1.433) (16.469)
2 Union rate zones 6,018 (13.448) (1.282) (14.729)
3 Total Balance (lines 1 + 2) (3)12,748 (28.483) (2.715) (31.198)
2023 IRP Operating Costs Deferral Account
4 Total Deferral Account (3)3.081 0.247 3.328
5 Direct Assignment to Union rate zones (2) (4)0.278 0.022 0.301
6 Remaining Balance to Be Allocated 2.803 0.225 3.028
Remaining Balance Allocation- 2018 Rate Base (1) (2)
7 EGD rate zone 6,729 1.480 0.119 1.598
8 Union rate zones 6,018 1.323 0.106 1.429
9 Total Remaining Balance Allocation 12,748 2.803 0.225 3.028
Total Balance Allocation
10 EGD rate zone (line 7)1.480 0.119 1.598
11 Union rate zones (line 5 + 8)1.602 0.129 1.730
12 Total Balance (lines 10 + 11)3.081 0.247 3.328
2023 Getting Ontario Connected
Allocation -2023 Number of Locates (2) (5)
13 EGD rate zone 605,137 19.782 1.077 20.858
14 Union South rate zone 299,532 9.792 0.533 10.325
15 Union North rate zones 71,250 2.329 0.127 2.456
16 Total Balance (lines 1 + 2) (3)975,919 31.903 1.736 33.639
2023 Accounting Policy Changes
Allocation -Direct Assigned (2) (6)
17 EGD rate zone (7.713) (8.669) 0.956 (7.713)
18 Union rate zones 13.260 14.180 (0.920) 13.260
19 Total Balance (lines 1 + 2) (3)5.547 5.511 0.036 5.547
Notes:
(1)
(2) Principal and interest allocated in proportion to column (a).
(3) Exhibit C, Tab 1, Schedule 1.
(4) Direct assignment to Union North rate zone consistent with evidence presented at Exhibit F, Tab 1, page 3.
(5) Exhibit C, Tab 1, Schedule 6.
(6) Direct assignment to rate zones consistent with evidence presented at Exhibit C, Tab 1, Table 2.
Enbridge Gas Inc.
Split of EGI Account Balances to Rate Zones
Account Balance
2018 actual rate base per EB-2019-0105, Exhibit B, Tab 2, Appendix B, Schedule 1 for the EGD rate zone and EB-2019-0105,
Exhibit C, Tab 2, Appendix A, Schedule 4 for the Union rate zones.
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 1
Schedule 1 Page 1 of 1
Page 481
COL.1
UNIT RATE
(¢/m³)
Bundled Services:
RATE 1 -SYSTEM SALES (0.2134)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE 0.3502
-DAWN T-SERVICE 0.3502
-WESTERN T-SERVICE (0.2134)
RATE 6 -SYSTEM SALES (0.2949)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE 0.2686
-DAWN T-SERVICE 0.2686
-WESTERN T-SERVICE (0.2949)
RATE 9 -SYSTEM SALES 0.0000
-BUY/SELL 0.0000
-ONTARIO T-SERVICE 0.0000
-DAWN T-SERVICE 0.0000
-WESTERN T-SERVICE 0.0000
RATE 100 -SYSTEM SALES (0.5379)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE 0.0257
-DAWN T-SERVICE 0.0257
-WESTERN T-SERVICE 0.0000
RATE 110 -SYSTEM SALES (0.5876)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE (0.0241)
-DAWN T-SERVICE (0.0241)
-WESTERN T-SERVICE (0.5876)
RATE 115 -SYSTEM SALES (0.5966)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE (0.0330)
-DAWN T-SERVICE (0.0330)
-WESTERN T-SERVICE 0.0000
RATE 135 -SYSTEM SALES (0.6224)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE 0.0000
-DAWN T-SERVICE (0.0589)
-WESTERN T-SERVICE 0.0000
RATE 145 -SYSTEM SALES (0.6496)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE 0.0000
-DAWN T-SERVICE (0.0860)
-WESTERN T-SERVICE 0.0000
RATE 170 -SYSTEM SALES (0.5881)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE (0.0245)
-DAWN T-SERVICE (0.0245)
-WESTERN T-SERVICE 0.0000
RATE 200 -SYSTEM SALES (0.5180)
-BUY/SELL 0.0000
-ONTARIO T-SERVICE 0.0000
-DAWN T-SERVICE 0.0455
-WESTERN T-SERVICE 0.0000
Unbundled Services (Billing based on CD):
RATE 125 -All (2.1665)
RATE 300 -All 0.9577
RATE 332 -All (1.7240)
Unit Rate and Type of Service: Clearing in January 2025
Enbridge Gas Inc.
EGD Rate Zone
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 2
Schedule 1 Page 1 of 1
Page 482
Enbridge Gas Inc.EGD Rate ZoneDetermination of Balances to be ClearedFrom the 2023 Deferral and Variance AccountsCOL. 1 COL. 2 COL. 3ITEMPRINCIPAL TOTALNO.FOR CLEARINGINTERESTFOR CLEARING($000) ($000) ($000)EGD RATE ZONE1.TRANSACTIONAL SERVICES D/A(41,738.1) (2,291.5) (44,029.6) 2.UNACCOUNTED FOR GAS V/A(6,922.7) (266.5) (7,189.2) 3.STORAGE AND TRANSPORTATION D/A18,705.8 1,572.8 20,278.6 4.DEFERRED REBATE ACCOUNT2,132.7 187.1 2,319.8 5.OEB COST ASSESSMENT VARIANCE ACCOUNT3,732.8 302.1 4,034.9 6.AVERAGE USE TRUE-UP V/A14,307.1 785.5 15,092.6 7.TRANSITION IMPACT OF ACCT CHANGE D/A- - - 8.INCREMENTAL CAPTIAL MODULE D/A(4,909.0) (232.4) (5,141.4) 9.DAWN ACCESS COSTS D/A- - - 10.RNG INJECTION SERVICES V/A(331.5) (28.7) (360.2) 11.EGD RATE ZONE SUB-TOTAL(15,022.9) 28.4 (14,994.5) EGI ACCOUNTS12.TAX VARIANCE - ACCELERATED CCA - EGD RATE ZONE PORTION(15,035.8) (1,433.2) (16,469.0) 13.IRP OPERATING COST DEFERRAL ACCOUNT - EGD RATE ZONE PORTION 1,479.5 118.7 1,598.3 14.GETTING ONTARIO CONNECTED V/A19,781.8 1,076.6 20,858.4 15.ACCOUTING POLICY CHANGES D/A(8,669.0) 956.2 (7,712.8) 16.EGI SUB-TOTAL(2,443.4) 718.3 (1,725.1) 17.TOTAL(17,466.3) 746.7 (16,719.6) Filed: 2024-05-31 EB-2024-0125 Exhibit F Tab 2 Schedule 2 Page 1 of 1Page 483
Enbridge Gas Inc.EGD Rate ZoneClassification and Allocation of Deferral and Variance Account BalancesCOL.1COL. 2COL. 3 COL. 4 COL. 5 COL. 6 COL. 7 COL. 8 COL. 9 COL. 10 COL. 11BUNDLEDITEMSALESDELIVERYTOTALDELIVE-NUMBER OFRATEANNUALGOCANO.TOTALAND WBTDEMAND TP > 4"DELIVERIESSPACERABILITYDIRECTCUSTOMERSBASEDELIVERIESALLOCATION($000)($000)($000)($000) ($000) ($000) ($000) ($000) ($000) ($000) ($000)CLASSIFICATION1. TRANSACTIONAL SERVICES D/A(44,029.6) (43,851.0)(60.8) (117.8)2. UNACCOUNTED FOR GAS V/A(7,189.2)(7,189.2)3. STORAGE AND TRANSPORTATION D/A20,278.66,903.4 13,375.24. DEFERRED REBATE ACCOUNT2,319.82,319.85. OEB COST ASSESSMENT VARIANCE ACCOUNT 4,034.94,034.96. TAX VARIANCE - ACCELERATED CCA - EGI(16,469.0)(16,469.0)7. AVERAGE USE TRUE-UP V/A15,092.615,092.68. ACCOUNTING POLICY CHANGES D/A(7,712.8)(1,997.4)(5,715.4)9. INCREMENTAL CAPITAL MODULE D/A(5,141.4)(5,141.4) 0.00.0 10. IRP OPERATING COST DEFERRAL ACCOUNT - EGI 1,598.31,598.3 11. RNG INJECTION SERVICE V/A(360.2)(360.2)0.0 12. TRANSITION IMPACT OF ACCT CHANGE D/A0.00.0 13. GETTING ONTARIO CONNECTED V/A20,858.40.0 20,858.4TOTAL(16,719.6) (43,851.0)(5,141.4) (5,229.7) 6,842.6 11,260.0 15,092.6 0.0 (16,551.2) 0.0 20,858.4ALLOCATION1.1 RATE 1(9,669.7) (26,047.6)(2,381.0) (2,157.8) 3,273.7 6,184.7 9,250.9 0.0 (10,857.4) 0.0 13,064.91.2 RATE 6(4,258.7) (16,212.2)(2,090.7) (2,053.0) 3,132.6 4,879.3 5,841.7 0.0 (4,583.2) 0.06,826.61.3 RATE 90.00.00.0 0.0 0.00.00.0 0.0 0.0 0.00.01.4 RATE 100(64.2)(77.0)0.0 (23.1) 32.654.80.0 0.0 (51.5) 0.00.01.5 RATE 110(1,043.3)(741.4)(116.6) (578.6) 211.426.30.0 0.0 (198.7) 0.0354.31.6 RATE 115(118.2)(0.9)(72.2) (163.8) 30.310.50.0 0.0 (72.9) 0.0150.91.7 RATE 125(200.6)0.0(413.1) 0.0 0.00.00.0 0.0 (159.5) 0.0372.01.8 RATE 135(48.7)(9.3)(0.2) (30.8) 0.00.00.0 0.0 (9.1) 0.00.81.9 RATE 145(42.1)0.8(4.8) (23.0) (13.4)0.00.0 0.0 (16.3) 0.014.61.10RATE 170(68.6)(8.8)(4.7) (112.5) 66.10.00.0 0.0 (22.9) 0.014.21.11RATE 200(668.8)(754.6)(57.4) (86.9) 109.4 104.40.0 0.0 (41.5) 0.057.91.12RATE 3000.10.0(0.7) 0.0 0.00.00.0 0.0 (1.3) 0.02.11.13RATE 332(536.9)0.00.0 0.0 0.00.00.0 0.0 (536.9) 0.0(16,719.6) (43,851.0)(5,141.4) (5,229.7) 6,842.6 11,260.0 15,092.6 0.0 (16,551.2) 0.0 20,858.4Filed: 2024-05-31 EB-2024-0125 Exhibit F Tab 2 Schedule 3 Page 1 of 1Page 484
COL.1 COL. 2 COL. 3 COL. 4 COL. 5 COL. 6 COL. 7 COL. 8 COL. 9 COL. 10 COL.11 BUNDLEDSALES DELIVERY TOTALDELIVE-NUMBER OF RATE ANNUAL GOCATOTAL AND WBT DEMAND TP > 4" DELIVERIES SPACE RABILITY DIRECT CUSTOMERS BASEDELIVERIES ALLOCATION($000) ($000) ($000) ($000) ($000) ($000) ($000) ($000) ($000) ($000) ($000)Bundled Services:RATE 1- SYSTEM SALES(9,846.4) (26,004.3) (2,349.0) (2,128.8) 3,229.7 6,101.6 9,126.6 - (10,711.5) - 12,889.3 - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT0.0 -(0.0) (0.0) 0.0 0.0 0.0 - (0.0) - 0.0 - DAWN T-SERVICE193.1 -(28.1) (25.4) 38.6 72.9 109.1 - (128.0) - 154.1 - WBT(16.4) (43.3) (3.9) (3.5) 5.4 10.2 15.2 - (17.8) - 21.5 RATE 6- SYSTEM SALES(8,259.7) (15,782.3) (1,315.7) (1,292.0) 1,971.4 3,070.7 3,676.3 - (2,884.3) - 4,296.2 - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT103.3 -(18.1) (17.8) 27.1 42.2 50.5 - (39.6) - 59.0 - DAWN T-SERVICE4,122.6 -(721.1) (708.1) 1,080.4 1,682.8 2,014.7 - (1,580.7) - 2,354.4 - WBT(225.0) (429.9) (35.8) (35.2) 53.7 83.6 100.1 - (78.6) - 117.0 RATE 9- SYSTEM SALES- - - - - - - - - - - - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT- - - - - - - - - - - - DAWN T-SERVICE- - - - - - - - - - - - WBT- - - - - - - - - - - RATE 100- SYSTEM SALES(73.5) (77.0) - (6.3) 8.9 15.0 - - (14.1) - - - BUY/SELL- - - -- - - - - - - - T-SERVICE EXCL WBT(0.1) - - 0.2 (0.2) (0.4) - - 0.3 - - - DAWN T-SERVICE9.4 - - (16.9) 23.9 40.2 - - (37.8) - - - WBT- - - - - - - - - - - RATE 110- SYSTEM SALES(706.1) (677.1) (11.2) (55.4) 20.3 2.5 - - (19.0) - 33.9 - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT(12.3) -(4.8) (23.6) 8.6 1.1 - - (8.1) - 14.5 - DAWN T-SERVICE(257.9) -(99.6) (494.3) 180.6 22.4 - - (169.7) - 302.7 - WBT(67.0) (64.3) (1.1) (5.3) 1.9 0.2 - - (1.8) - 3.2 RATE 115- SYSTEM SALES(0.9) (0.9) (0.0) (0.1) 0.0 0.0 - - (0.0) - 0.1 - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT(35.0) -(21.5) (48.9) 9.0 3.1 - - (21.7) - 45.0 - DAWN T-SERVICE(82.2) -(50.6) (114.9) 21.2 7.3 - - (51.1) - 105.8 - WBT- - - - - - - - - - - RATE 135- SYSTEM SALES(10.3) (9.3) (0.0) (0.8) - - - - (0.2) - 0.0 - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT- - - - - - - - - - - - DAWN T-SERVICE(38.4) -(0.2) (30.1) - - - - (8.9) - 0.8 - WBT- - - - - - - - - - - RATE 145- SYSTEM SALES0.9 0.8 0.0 0.1 0.0 - - - 0.0 - (0.0) - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT- - - - - - - - - - - - DAWN T-SERVICE(43.0) -(4.8) (23.1) (13.4) - - - (16.4) - 14.6 - WBT- - - - - - - - - - - RATE 170- SYSTEM SALES(9.2) (8.8) (0.0) (0.7) 0.4 - - - (0.1) - 0.1 - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT(26.2) -(2.0) (49.3) 29.0 - - - (10.0) - 6.2 - DAWN T-SERVICE(33.2) -(2.6) (62.5) 36.7 - - - (12.7) - 7.9 - WBT- - - - - - - - - - - RATE 200- SYSTEM SALES(693.6) (754.6) (40.8) (61.8) 77.7 74.2 - - (29.5) - 41.1 - BUY/SELL- - - - - - - - - - - - T-SERVICE EXCL WBT- - - - - - - - - - - - DAWN T-SERVICE24.8 -(16.6) (25.2) 31.7 30.2 - - (12.0) - 16.7 - WBT- - - - - - - - - - - Unbundled Services: (Billing based on CD)RATE 125(200.6) -(413.1) - - - - - (159.5) - 372.0 RATE 3000.1-(0.7) - - - - - (1.3) - 2.1 RATE 332(536.9) --- - - - - (536.9) - -(16,719.6) (43,851.0) (5,141.4) (5,229.7) 6,842.6 11,260.0 15,092.60.0 (16,551.2) 0.0 20,858.4Allocation by Type of ServiceEnbridge Gas Inc.EGD Rate ZoneFiled: 2024-05-31 EB-2024-0125 Exhibit F Tab 2 Schedule 4 Page 1 of 1Page 485
COL.1 COL. 2 COL. 3 COL. 4 COL. 5 COL. 6 COL. 7 COL. 8 COL. 9 COL. 10 COL. 11
BUNDLED
SALES DELIVERY TOTAL DELIVE-NUMBER OF RATE ANNUAL GOCA
TOTAL AND WBT DEMAND TP > 4" DELIVERIES SPACE RABILITY DIRECT CUSTOMERS BASE DELIVERIES ALLOCATION
(¢/m³) (¢/m³) (¢/m³)(¢/m³) (¢/m³) (¢/m³) (¢/m³) (¢/m³) (¢/m³) (¢/m³) (¢/m³)
Bundled Services:RATE 1 - SYSTEM SALES (0.2134) (0.5635)(0.0509) (0.0461) 0.0700 0.1322 0.1978 0.0000 (0.2321)0.0000 0.2793- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC 0.3502 0.0000 (0.0509) (0.0461) 0.0700 0.1322 0.1978 0.0000 (0.2321)0.0000 0.2793- DAWN T-SERVICE 0.3502 0.0000 (0.0509) (0.0461) 0.0700 0.1322 0.1978 0.0000 (0.2321)0.0000 0.2793- WESTERN T-SERVI (0.2134) (0.5635)(0.0509) (0.0461) 0.0700 0.1322 0.1978 0.0000 (0.2321)0.0000 0.2793RATE 6 - SYSTEM SALES (0.2949) (0.5635)(0.0470) (0.0461) 0.0704 0.1096 0.1313 0.0000 (0.1030)0.0000 0.1534- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC 0.2686 0.0000 (0.0470) (0.0461) 0.0704 0.1096 0.1313 0.0000 (0.1030)0.0000 0.1534- DAWN T-SERVICE 0.2686 0.0000 (0.0470) (0.0461) 0.0704 0.1096 0.1313 0.0000 (0.1030)0.0000 0.1534- WESTERN T-SERVI (0.2949) (0.5635)(0.0470) (0.0461) 0.0704 0.1096 0.1313 0.0000 (0.1030)0.0000 0.1534RATE 9 - SYSTEM SALES 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- DAWN T-SERVICE 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- WESTERN T-SERVI 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000RATE 100 - SYSTEM SALES (0.5379) (0.5635)0.0000 (0.0461) 0.0652 0.1096 0.0000 0.0000 (0.1030)0.0000 0.0000- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC 0.0257 0.0000 0.0000 (0.0461) 0.0652 0.1096 0.0000 0.0000 (0.1030)0.0000 0.0000- DAWN T-SERVICE 0.0257 0.0000 0.0000 (0.0461) 0.0652 0.1096 0.0000 0.0000 (0.1030)0.0000 0.0000- WESTERN T-SERVI 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000RATE 110 - SYSTEM SALES (0.5876) (0.5635)(0.0093) (0.0461) 0.0169 0.0021 0.0000 0.0000 (0.0158)0.0000 0.0282- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC (0.0241) 0.0000 (0.0093) (0.0461) 0.0169 0.0021 0.0000 0.0000 (0.0158)0.0000 0.0282- DAWN T-SERVICE (0.0241) 0.0000 (0.0093) (0.0461) 0.0169 0.0021 0.0000 0.0000 (0.0158)0.0000 0.0282- WESTERN T-SERVI (0.5876) (0.5635)(0.0093) (0.0461) 0.0169 0.0021 0.0000 0.0000 (0.0158)0.0000 0.0282RATE 115 - SYSTEM SALES (0.5966) (0.5635)(0.0203) (0.0461) 0.0085 0.0030 0.0000 0.0000 (0.0205)0.0000 0.0425- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC (0.0330) 0.0000 (0.0203) (0.0461) 0.0085 0.0030 0.0000 0.0000 (0.0205)0.0000 0.0425- DAWN T-SERVICE (0.0330) 0.0000 (0.0203) (0.0461) 0.0085 0.0030 0.0000 0.0000 (0.0205)0.0000 0.0425- WESTERN T-SERVI 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000RATE 135 - SYSTEM SALES (0.6224) (0.5635)(0.0004) (0.0461) 0.0000 0.0000 0.0000 0.0000 (0.0136)0.0000 0.0013- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- DAWN T-SERVICE (0.0589) 0.0000 (0.0004) (0.0461) 0.0000 0.0000 0.0000 0.0000 (0.0136)0.0000 0.0013- WESTERN T-SERVI 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000RATE 145 - SYSTEM SALES (0.6496) (0.5635)(0.0096) (0.0461) (0.0268) 0.0000 0.0000 0.0000 (0.0327)0.0000 0.0292- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- DAWN T-SERVICE (0.0860) 0.0000 (0.0096) (0.0461) (0.0268) 0.0000 0.0000 0.0000 (0.0327)0.0000 0.0292- WESTERN T-SERVI 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
RATE 170 - SYSTEM SALES (0.5881) (0.5635)(0.0019) (0.0461) 0.0271 0.0000 0.0000 0.0000 (0.0094)0.0000 0.0058- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC (0.0245) 0.0000 (0.0019) (0.0461) 0.0271 0.0000 0.0000 0.0000 (0.0094)0.0000 0.0058- DAWN T-SERVICE (0.0245) 0.0000 (0.0019) (0.0461) 0.0271 0.0000 0.0000 0.0000 (0.0094)0.0000 0.0058- WESTERN T-SERVI 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000RATE 200 - SYSTEM SALES (0.5180) (0.5635)(0.0305) (0.0461) 0.0580 0.0554 0.0000 0.0000 (0.0220)0.0000 0.0307- BUY/SELL 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- ONTARIO T-SERVIC 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000- DAWN T-SERVICE 0.0455 0.0000 (0.0305) (0.0461) 0.0580 0.0554 0.0000 0.0000 (0.0220)0.0000 0.0307- WESTERN T-SERVI 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000
Unbundled Services (Billing based on CD, ¢/m3):
RATE 125 - All (2.1665) 0.0000 (4.4612) 0.0000 0.0000 0.0000 0.0000 0.0000 (1.7229)0.0000 4.0177
- Customer-specific **
RATE 300 - All 0.9577 0.0000 (4.4612) 0.0000 0.0000 0.0000 0.0000 0.0000 (8.1385)0.0000 13.5574
- Customer-specific **
RATE 332 - All (1.7240) 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 (1.7240)0.0000 0.0000
Notes:
* Unit Rates derived based on 2023 actual volumes
Unit Rate by Type of Service*
Enbridge Gas Inc.
EGD Rate Zone
Filed: 2024-05-31 EB-2024-0125
Exhibit F
Tab 2
Schedule 5
Page 1 of 1
Page 486
ITEMNO.COL. 1COL. 2COL. 3COL. 4COL. 5COL. 6COL. 7COL. 8COL. 9COL. 10GENERAL SERVICEANNUAL VOLUMESALESONTARIO TSDAWN TSWESTERN TSSALES CUSTOMERSONTARIO TS CUSTOMERSDAWN TS CUSTOMERSWESTERN TS CUSTOMERSm3(¢/m3)(¢/m3)(¢/m3)(¢/m3)($)($)($)($)1.1 RATE 1 RESIDENTIAL1.2 Heating & Water Heating 2,400(0.2134) 0.3502 0.3502 (0.2134)(5.12) 8.40 8.40 (5.12) 2.1 RATE 6 COMMERCIAL2.2 Heating & Other Uses 22,606(0.2949) 0.2686 0.2686 (0.2949)(66.67) 60.72 60.72 (66.67) 2.3General Use 43,285(0.2949) 0.2686 0.2686 (0.2949)(127.66) 116.27 116.27 (127.66) CONTRACT SERVICE3.1RATE 100 3.2Industrial - small size 339,188(0.5379) 0.0257 0.0257 0.0000(1,824.34) 87.10 87.10 - 4.1RATE 110 4.2 Industrial - small size, 50% LF 598,568(0.5876) (0.0241) (0.0241) (0.5876)(3,517.23) (144.08) (144.08) (3,517.23) 4.3 Industrial - avg. size, 75% LF 9,976,121(0.5876) (0.0241) (0.0241) (0.5876)(58,620.35) (2,401.34) (2,401.34) (58,620.35) 5.1RATE 115 5.2 Industrial - small size, 80% LF 4,471,609(0.5966) (0.0330) (0.0330) 0.0000(26,676.30) (1,477.18) (1,477.18) - 6.1RATE 135 6.2 Industrial - Seasonal Firm 598,567(0.6224) 0.0000 (0.0589) 0.0000(3,725.49) - (352.35) - 7.1RATE 145 7.2 Commercial - avg. size 598,568(0.6496) 0.0000 (0.0860) 0.0000(3,888.16) - (515.02) - 8.1RATE 170 8.2 Industrial - avg. size, 75% LF 9,976,121(0.5881) (0.0245) (0.0245) 0.0000(58,664.59) (2,445.58) (2,445.58) - Notes:Col. 7 = Col. 2 x Col. 3Col. 8 = Col. 2 x Col. 4Col. 9 = Col. 2 x Col. 5Col. 10 = Col. 2 x Col. 6Enbridge Gas Inc.2023 Deferral and Variance Account ClearingBill Adjustment in January 2025 for Typical CustomersUNIT RATEBILL ADJUSTMENTEGD Rate ZoneFiled: 2024-05-31 EB-2024-0125 Exhibit F Tab 2 Schedule 6 Page 1 of 1Page 487
Sales/System Gas Bundled T-Service T-Service
Unit Rate for Billing Unit Rate for BillingUnit Rate for Billing
Line Unit Rate Unit Rate Unit Rate
No. Particulars (cents/m3) (cents/m
3) (cents/m
3)
(a) (b) (c)
Union North West
1 Rate 01 0.0060 0.0060 0.2907
2 Rate 10 0.6920 0.6920 0.8502
3 Rate 20 0.3875 0.3875 0.0115
4 Rate 25 0.1444 0.1444 0.0061
5 Rate 100 0.0119 0.0119 0.0119
6 Bundled-T Storage Service ($/GJ)- - 0.086
Union North East
7 Rate 01 0.0214 0.0214 0.2907
8 Rate 10 0.6237 0.6237 0.8502
9 Rate 20 (3.1925) (3.1925) 0.0115
10 Rate 25 (0.1114) (0.1114) 0.0061
11 0.0119 0.0119 0.0119
12 - - 0.086
13
Rate 100
Bundled-T Storage Service ($/GJ)
North T-Service Transportation from Dawn Base Service ($/GJ)- - 0.355
Union South
14 Rate M1 0.4323 0.0729 -
15 Rate M2 0.3618 0.0024 -
16 Rate M4 0.3472 (0.0122) -
17 Rate M5 0.5883 0.2289 -
18 Rate M7 0.3583 (0.0011) -
19 Rate M9 0.3588 (0.0005) -
20 Rate T1 - - (0.0095)
21 Rate T2 - - (0.0081)
22 Rate T3 - - 0.0024
Enbridge Gas Inc.
Union Rate Zones
Unit Rate and Type of Service
2023 Deferral Account Disposition
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 3
Schedule 1 Page 1 of 1
Page 488
Line Account
No. Number Account Name ($000's) Balance Interest Total
(a) (b) (c)
1 179-131 Upstream Transportation Optimization 8,087 444 8,531
2 179-107 Spot Gas Variance Account - - -
3 179-108 Unabsorbed Demand Costs Variance Account 42 38 79
4 179-153 Base Service North T-Service TransCanada Capacity 79 6 85
5 179-070 Short-Term Storage and Other Balancing Services 1,638 90 1,727
6 179-133 Normalized Average Consumption (3,651) (201) (3,852)
7 179-132 Deferral Clearing Variance Account 3,372 184 3,557
8 179-151 OEB Cost Assessment Variance Account 1,630 131 1,761
9 179-103 Unbundled Services Unauthorized Storage Overrun - - -
10 179-112 Gas Distribution Access Rule Costs - - -
11 179-123 Conservation Demand Management - - -
12 179-136 Parkway West Project Costs (696) (49) (745)
13 179-137 Brantford-Kirkwall/Parkway D Project Costs (3) (0) (3)
14 179-142 Lobo C Compressor/Hamilton-Milton Pipeline Project Costs 268 10 278
15 179-144 Lobo D/Bright C/Dawn H Compressor Project Costs 66 (39) 27
16 179-149 Burlington-Oakville Project Costs (43) (3) (46)
17 179-156 Panhandle Reinforcement Project Costs (1,884) (146) (2,030)
18 179-162 Sudbury Replacement Project - - -
19 179-138 Parkway Obligation Rate Variance - - -
20 179-143 Unauthorized Overrun Non-Compliance Account (46) (4) (50)
21 179-159 Incremental Capital Module (384) (504) (888)
22 179-157 Pension and OPEB Forecast Accrual vs. Actual Cash Payment Differential V/A - (6,208) (6,208)
23 179-135 Unaccounted for Gas Volume Variance Account - --
24 179-141 Unaccounted for Gas Price Variance Account (629) (132) (761)
25 Total for Union Rate Zone Specific Accounts (Lines 1 through 24)7,846 (6,384) 1,462
26 179-382 Earnings Sharing (Union Rate Zones Portion)- - -
27 179-383 Tax Variance - Accelerated CCA (Union Rate Zones Portion)(13,448) (1,282) (14,729)
28 179-385 IRP Operating Costs Deferral Account (Union Rate Zones Portion)1,602 129 1,730
29 179-386 IRP Capital Costs Deferral Account - - -
30 179-387 Green Button Initiative D/A - - -
31 Cloud Computing Implementation Costs D/A - - -
32 179-324 Getting Ontario Connected V/A 12,121 660 12,780
33 179-380 Expansion of Natural Gas Distribution Systems V/A (Union Rate Zones Portion)- - -
34 179-381 Accounting Policy Changes D/A - Other - EGI 14,180 (920) 13,260
35 179-384 Impacts Arising from the COVID-19 Emergency D/A - EGI - - -
36 Total for EGI Accounts allocated to Union Rate Zones (Lines 26 through 35)14,455 (1,414) 13,041
37 Total Union Rate Zones Deferral Account Balances (Line 25 + Line 36)22,301 (7,798) 14,503
Enbridge Gas Inc.
Union Rate Zones
2023 Deferral Account Balances To Be Cleared
Year Ending December 31, 2023
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 3
Schedule 2 Page 1 of 1
Page 489
LineAcctExcessNo. Particulars ($000's)No. Rate 01 Rate 10 Rate 20 Rate 100 Rate 25 M1 M2 M4 M5A M7 M9 T1 T2 T3 M12 M13 Utility C1 M16 M17 Total(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m) (n) (o) (p) (q) (r) (s) (t) (u) (v)Gas Supply Related Deferrals:1 Upstream Transportation Optimization179-131 (661) (258) (133) - 14 7,865 1,445 149 5 54 50 - - - - - - - - - 8,531 2 Spot Gas Variance Account179-107 - -- - - - - - - - - - - - - - - - - - - 3 Unabsorbed Demand Cost (UDC) Variance Account179-108 (1,889) (386) (79) - - 2,000 367 38 1 14 13 - - - - - - - - - 79 4 Base Service North T-Service TransCanada Capacity Account179-153 - - 62 22 - - - - - - - - - - - - - - - - 85 5 Total Gas Supply Related Deferrals (2,549) (644) (150) 22 14 9,865 1,812 187 6 68 63 - - - - - - - - - 8,695 Storage Related Deferrals:6 Short-Term Storage and Other Balancing Services179-70 236 67 36 1 - 538 203 91 1 51 9 39 411 44 - - - - - - 1,727 Delivery Related Deferrals:7 Normalized Average Consumption (NAC)179-133 741 2,222 - - - (5,706) (1,110) - - - - - - - - - - - - - (3,852) 8 Deferral Clearing Variance Account179-132 619 203 3 3 1 1,942 764 2 0 2 0 1 16 1 - - - - - - 3,557 9 OEB Cost Assessment Variance Account179-151 353 31 26 23 11 890 84 31 35 9 1 23 62 7 166 0 7 4 0 - 1,761 10 Unbundled Services Unauthorized Storage Overrun179-103 - - - - - - - - - - - - - - - - - - - - - 11 Gas Distribution Access Rule Costs 179-112 - - - - - - - - - - - - - - - - - - - - - 12 Conservation Demand Management179-123 - - - - - - - - - - - - - - - - - - - - - 13 Parkway West Project Costs179-136 4 (10) (1) 2 1 126 5 3 4 0 (0) 5 24 (2) (914)0 1 4 0 - (745) 14 Brantford-Kirkwall/Parkway D Project Costs179-137 (1) (0) (0) (0) (0) (1) (0) (0) (0) (0) (0) (0) (0) (0) (1) (0) (0) (0) (0) - (3) 15 Lobo C Compressor/Hamilton-Milton Pipeline Project Costs179-142 (7) 4 0 (1) (1) (84) (7) (3) (3) (1) (0) (4) (23) (0) 409(0) (0) (0) (0) - 278 16 Lobo D/Bright C/Dawn H Compressor Project Costs179-144 (38) (1) (2) (2) (1) (94) (1) (1) (4) 0 0 (2) (1) 2 176 0 (2) (1) (0) - 27 17 Burlington-Oakville Project Costs179-149 (3) (0) (0) (0) (0) (23) (7) (2) (0) (1) (0) (2) (12) (2) 6 0 (0) 0 0 - (46) 18 Panhandle Reinforcement Project Costs179-156 (42) (7) (5) (4) (1) (466) (149) (153) (6) (34) (0) (102) (741) (1) (55)(0) (1) (217) (47) - (2,030) 19 Sudbury Replacement Project179-162 - -- - - - - - - - - - - - - - - - - -- 20 Parkway Obligation Rate Variance179-138 - -- - - - - - - - - - - - - - - - - -- 21 Unauthorized Overrun Non-Compliance Account179-143 - -- - - (20) (7) (4) (0) (2) (0) (1) (15) (2) - - - - - -(50) 22 Incremental Capital Module179-159 - -- - - (423) (153) (74) (3) (35) (3) (31) (155) (12) - - - - - -(888) 23 Pension & OPEB Forecast Accrual vs Actual Cash Payment Differential V/A 179-157 (1,247) (114) (112) (94) (45) (3,054) (295) (124) (142) (31) (5) (85) (215) (24) (588)(0) (20) (13) (1) - (6,208) 24 Unaccounted for Gas Volume Variance Account179-135 - - - - - - - - - - - - - - - - - - - -- 25 Unaccounted for Gas Price Variance Account179-141 (23) (3) (0) - (1) (108) (43) (21) (2) (28) (4) (7) (77) (5) (249)(1) - (184) (4) (0) (761) 26 Tax Variance - Accelerated CCA - EGI179-383 (2,618) (403) (286) (220) (78) (5,717) (866) (215) (183) (75) (14) (149) (660) (87) (3,038) (2) (85) (27) (4) - (14,729) 27 IRP Operating Costs Deferral Account - EGI179-385 366 75 90 97 23 555 84 21 18 7 1 14 64 8 295 0 8 3 0 - 1,730 28 IRP Capital Costs Deferral Account - EGI179-386 - - - - - - - - - - - - - - - - - - - - - 29 Green Button Initiative Deferral Account - EGI179-387 - - - - - - - - - - - - - - - - - - - - - 30 Getting Ontario Connected - EGI 179-324 2,010 170 127 111 38 8,629 746 187 256 60 - 129 317 - - - - - - - 12,780 31 Expansion of Natural Gas Distribution Systems V/A 179-380 - - - - - - - - - - - - - - - - - - - - - 32 Accounting Policy Changes D/A - Other - EGI179-381 2,356 363 257 198 70 5,147 780 194 164 68 13 134 594 78 2,735 2 77 25 3 - 13,260 33 Impacts Arising from the COVID-19 Emergency D/A - EGI179-384 - - - - - - - - - - - - - - - - - - - - - 34 Total Delivery-Related Deferrals2,472 2,529 98 112 16 1,594 (175) (160) 134 (59) (10) (77) (821) (38) (1,058)(1) (15) (407) (52) (0) 4,081 35 Total 2023 Storage and Delivery Disposition (Line 6 + Line 34)2,708 2,595 134 114 16 2,132 28 (69) 135 (9) (1) (38) (410) 6 (1,058) (1) (15) (407) (52) (0) 5,808 36 Total 2023 Deferral Account Disposition (Line 5 + Line 35)159 1,951 (15) 136 30 11,997 1,841 118 141 59 62 (38) (410) 6 (1,058) (1) (15) (407) (52) (0) 14,503 37 Earnings Sharing Deferral Account - EGI179-382 - - - - - - - - - - - - - - - - - - - - - 38 Grand Total (Line 36 + Line 37)159 1,951 (15) 136 30 11,997 1,841 118 141 59 62 (38) (410) 6 (1,058) (1) (15) (407) (52) (0) 14,503 Enbridge Gas Inc.Union Rate ZonesClassification and Allocation of Deferral and Variance Account BalancesUnion NorthUnion SouthFiled: 2024-05-31 EB-2024-0125 Exhibit F Tab 3 Schedule 3 Page 1 of 2Page 490
LineAcctNo. Particulars ($000's) No. Rate 01 Rate 10 Rate 20 Rate 100 Rate 25 Total(a) (b) (c) (d) (e) (f) (g)= (sum b:f)Union North WestGas Supply Related Deferrals:1 Spot Gas Variance Account179-107- - - - - - 2Unabsorbed Demand Cost (UDC) Variance Account179-108 (1,305) (246) (57) - - (1,608) 3 Upstream Transportation Optimization179-131 562 136 63 -42804 4Total Gas Supply Related Deferrals (744) (110) 7 -42(804) Storage Related Deferrals:5 Short-Term Storage and Other Balancing Services (1)179-7067 17 3 - - 88 6Total North West Deferral Account Disposition (Line 4 + Line 5)(676) (93) 10 -42(717) Union North EastGas Supply Related Deferrals: 7 Spot Gas Variance Account179-107- - - - - - 8Unabsorbed Demand Cost (UDC) Variance Account179-108 (583) (140) (22) -- (746) 9Upstream Transportation Optimization179-131 (1,223) (394) (196) -(28) (1,841) 10 Total Gas Supply Related Deferrals (1,806) (534) (219) -(28) (2,587) Storage Related Deferrals:11 Short-Term Storage and Other Balancing Services (1)179-70168 50 22 - - 240 12Total North East Deferral Account Disposition (Line 10 + Line 11)(1,637) (484) (197) -(28) (2,346) Total NorthGas Supply Related Deferrals: 13 Spot Gas Variance Account179-107- - - - - - 14Unabsorbed Demand Cost (UDC) Variance Account179-108 (1,889) (386) (79) - - (2,354) 15 Upstream Transportation Optimization179-131 (661) (258) (133) -14 (1,037) 16 Total North Gas Supply Related Deferrals (2,549) (644) (212) -14(3,391) Storage Related Deferrals:17 Short-Term Storage and Other Balancing Services (1)179-70236 67 25 - - 328 18Total North Deferral Account Disposition (Line 16 + Line 17)(2,313) (577) (187) -14(3,063) Notes:(1)Excludes allocation to Rate 20/100 bundled storage service.Enbridge Gas Inc.Union Rate ZonesAllocation of 2023 Gas Supply Related Deferral Accounts by Union North East and Union North WestFiled: 2024-05-31 EB-2024-0125 Exhibit F Tab 3 Schedule 3 Page 2 of 2Page 491
2023 Deferral2023 EarningsBalance 2023DeferralSharing forActualLineRate Balances Mechanism Disposition Volume Unit RateNo. ParticularsClass ($000's) ($000's) ($000's)(103m3) (cents/m3)(a) (b)(c) = (a + b)(d) (e) = (c / d) * 100Union North1 Small Volume General Service 01 2,708 - 2,708 931,782 0.2907 2 Large Volume General Service 10 2,595 - 2,595 305,249 0.8502 3 Medium Volume Firm Service20 123 - 123 1,074,225 0.0115 4 Large Volume High Load Factor 100 112 - 112 942,952 0.0119 5 Large Volume Interruptible25 16 - 16 255,665 0.0061 Union South6 Small Volume General Service M1 2,132 - 2,132 2,925,618 0.0729 7 Large Volume General Service M2 28 - 28 1,150,624 0.0024 8 Firm Com/Ind ContractM4 (69) - (69) 564,595 (0.0122) 9 Interruptible Com/Ind Contract M5 135 - 135 58,966 0.2289 10 Special Large Volume Contract M7 (9) - (9) 769,537 (0.0011) 11 Large WholesaleM9 (1) - (1) 97,880 (0.0005) 12 Contract Carriage ServiceT1 (38) - (38) 397,887 (0.0095) 13 Contract Carriage ServiceT2 (410) - (410) 5,069,101 (0.0081) 14 Contract Carriage- WholesaleT3 6 - 6 255,245 0.0024 Enbridge Gas Inc.Union Rate ZonesUnit Rates for One-Time Adjustment - Delivery2023 Deferral Account DispositionFiled: 2024-05-31 EB-2024-0125 Exhibit F Tab 3 Schedule 4 Page 1 of 4Page 492
2023 Deferral2023 Earnings Balance 2023Deferral Sharing for ActualLineRate Balances Mechanism Disposition Volume Unit RateNo. ParticularsClass ($000's) ($000's) ($000's)(103m3) (cents/m3)(a) (b)(c) = (a + b)(d) (e) = (c / d) * 1001 Small Volume General Service M1 9,865 - 9,865 2,744,946 0.3594 2 Large Volume General Service M2 1,812 - 1,812 504,297 0.3594 3 Firm Com/Ind ContractM4 187 - 187 51,991 0.3594 4 Interruptible Com/Ind Contract M56 - 6 1,767 0.3594 5 Special Large Volume Contract M7 68 - 68 18,856 0.3594 6 Large WholesaleM9 63 - 63 17,445 0.3594 Enbridge Gas Inc.Union Rate Zones Unit Rates for One-Time Adjustment - Gas Supply Commodity2023 Deferral Account DispositionFiled: 2024-05-31 EB-2024-0125 Exhibit F Tab 3 Schedule 4 Page 2 of 4Page 493
2023 Deferral2023 Earnings Balance 2023UnitDeferral Sharing forActualVolumetric/LineRate Balances Mechanism Disposition Volume/ Billing Demand RateNo. ParticularsClass ($000's) ($000's) ($000's) Demand Units(cents/m3)(a) (b) (c) = (a + b) (d) (e) = (c / d) * 100Gas Supply Transportation ChargesUnion North West1 Small Volume General Service01 (744) - (744) 261,185 103m3(0.2847) 2 Large Volume General Service 10 (110) - (110) 69,381 103m3(0.1582) 3 Medium Volume Firm Service 20 7 - 7 1,764 103m3/d0.3760 4 Large Volume Interruptible2542 - 42 30,655 103m30.1384 Union North East5 Small Volume General Service01 (1,806) - (1,806) 670,597 103m3(0.2693) 6 Large Volume General Service 10 (534) - (534) 235,867 103m3(0.2265) 7 Medium Volume Firm Service 20 (219) - (219) 6,820 103m3/d(3.2040) 8 Large Volume Interruptible25(28) - (28) 23,960 103m3(0.1175) North T-Service Transportation from Dawn9 Base Service ($/GJ) 20T/100T 85 - 85 237,864 GJ/d0.355 Storage ($/GJ)10Bundled-T Storage Service20T/100T 12 - 12 141,504 GJ/d0.086 Enbridg Gas Inc.Union Rate ZonesUnit Rates for One-Time Adjustment - Gas Supply Transportation and Bundled Storage2023 Deferral Account DispositionFiled: 2024-05-31 EB-2024-0125 Exhibit F Tab 3 Schedule 4 Page 3 of 4Page 494
2023Deferral2023 Earnings Balance LineRate Deferral SharingforNo. Particulars ($000's) (1)Class Balances Mechanism Disposition(a)(b) (c) = (a + b)1 TransportationM12(1,058) - (1,058) 2 Transportation of Locally Produced Gas M13(1) - (1) 3 Cross Franchise TransportationC1(407) - (407) 4 Storage and Transportation Services M16(52) - (52) 5 Transporation ServiceM17(0) (0) Notes:(1)Enbridge Gas Inc.Union Rate ZonesStorage and Transportation Service Amounts for Disposition2023 Deferral Account DispositionEx-franchise customer specific amounts determined using approved deferral account allocation methodologies.Filed: 2024-05-31 EB-2024-0125 Exhibit F Tab 3 Schedule 4 Page 4 of 4Page 495
Deferral Annual
Line Unit Rate Volume Bill Impact
No. Particulars (cents/m3) (m3) (1)($)
(a)(b) (c) = (a x b) / 100
Small Volume General Service
Rate M1 - Union South
1 Delivery 0.0729 2,200 1.60
2 Commodity 0.3594 2,200 7.91
3 Sales Service Impact 0.4323 9.51
4 Direct Purchase Impact 1.60
Rate 01 - Union North West
5 Delivery 0.2907 2,200 6.39
6 Commodity - 2,200 -
7 Transportation (0.2847) 2,200 (6.26)
8 Sales Service Impact 0.0060 0.13
9 Bundled-T (Direct Purchase) Impact 0.13
Rate 01 - Union North East
10 Delivery 0.2907 2,200 6.39
11 Commodity - 2,200 -
12 Transportation (0.2693) 2,200 (5.92)
13 Sales Service Impact 0.0214 0.47
14 Bundled-T (Direct Purchase) Impact 0.47
Large Volume General Service
Rate M2 - Union South
15 Delivery 0.0024 73,000 1.79
16 Commodity 0.3594 73,000 262.36
17 Sales Service Impact 0.3618 264.15
18 Direct Purchase Impact 1.79
Rate 10 - Union North West
19 Delivery 0.8502 93,000 790.70
20 Commodity - 93,000 -
21 Transportation (0.1582) 93,000 (147.15) 22 Sales Service Impact 0.6920 643.55
23 Bundled-T (Direct Purchase) Impact 643.55
Rate 10 - Union North East
24 Delivery 0.8502 93,000 790.70
25 Commodity - 93,000 -
26 Transportation (0.2265) 93,000 (210.62)
27 Sales Service Impact 0.6237 580.09
28 Bundled-T (Direct Purchase) Impact 580.09
Enbridge Gas Inc.
Union Rate Zones
Calculation of One-Time Adjustments for Typical General Service Customers
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 3
Schedule 5 Page 1 of 3
Page 496
Line
No.Particulars
Deferral Unit
Rate
(cents/m3)
Billing Units
(m3)
Bill Impact
($) (1)
(a)(b)(c)
Union North
Small Rate 20 - Union North West
1 Delivery 0.0115 3,000,000 344
2 Transportation 0.3760 14,000 632
3 Sales Service Impact 0.3875 976
4 Bundled-T (Direct Purchase) Impact 976
Large Rate 20 - Union North West
5 Delivery 0.0115 15,000,000 1,722
6 Transportation 0.3760 60,000 2,707
7 Sales Service Impact 0.3875 4,429
8 Bundled-T (Direct Purchase) Impact 4,429
Small Rate 20 - Union North East
9 Delivery 0.0115 3,000,000 344
10 Transportation (3.2040) 14,000 (5,383)
11 Sales Service Impact (3.1925) (5,038)
12 Bundled-T (Direct Purchase) Impact (5,038)
Large Rate 20 - Union North East
13 Delivery 0.0115 15,000,000 1,722
14 Transportation (3.2040) 60,000 (23,069)
15 Sales Service Impact (3.1925) (21,347)
16 Bundled-T (Direct Purchase) Impact (21,347)
Average Rate 25 - Union North West
17 Delivery 0.0061 2,275,000 138
18 Transportation 0.1384 2,275,000 3,148
19 Sales Service Impact 0.1444 3,286
20 Bundled-T (Direct Purchase) Impact 3,286
Average Rate 25 - Union North East
21 Delivery 0.0061 2,275,000 138
22 Transportation (0.1175) 2,275,000 (2,672)
23 Sales Service Impact (0.1114) (2,534)
24 Bundled-T (Direct Purchase) Impact (2,534)
Small Rate 100
25 T-Service (Direct Purchase) Impact 0.0119 27,000,000 3,220
Large Rate 100
26 T-Service (Direct Purchase) Impact 0.0119 240,000,000 28,623
Union South
Small Rate M4
27 Delivery (0.0122) 875,000 (107)
28 Commodity 0.3594 875,000 3,145
29 Sales Service Impact 0.3472 3,038
30 Direct Purchase Impact (107)
Large Rate M4
31 Delivery (0.0122) 12,000,000 (1,466)
32 Commodity 0.3594 12,000,000 43,128
33 Sales Service Impact 0.3472 41,662
34 Direct Purchase Impact (1,466)
Notes:
(1)Transportation bill impacts based on monthly demand (m3/d).
Enbridge Gas Inc.
Union Rate Zones
Calculation of One-Time Adjustments for Typical Small and Large Customers
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 3
Schedule 5 Page 2 of 3
Page 497
Line
No.Particulars
Deferral Unit
Rate
(cents/m3)
Billing Units
(m3)
Bill Impact
($) (1)
(a) (b) (c)
Union South (continued)
Small Rate M5 Interruptible
1 Delivery 0.2289 825,000 1,888
2 Commodity 0.3594 825,000 2,965
3 Sales Service Impact 0.5883 4,853
4 Direct Purchase Impact 1,888
Large Rate M5 Interruptible
5 Delivery 0.2289 6,500,000 14,876
6 Commodity 0.3594 6,500,000 23,361
7 Sales Service Impact 0.5883 38,237
8 Direct Purchase Impact 14,876
Small Rate M7
9 Delivery (0.0011) 36,000,000 (403)
10 Commodity 0.3594 36,000,000 129,383
11 Sales Service Impact 0.3583 128,981
12 Direct Purchase Impact (403)
Large Rate M7
13 Delivery (0.0011) 52,000,000 (582)
14 Commodity 0.3594 52,000,000 186,887
15 Sales Service Impact 0.3583 186,306
16 Direct Purchase Impact (582)
Small Rate M9
17 Delivery (0.0005) 6,950,000 (38)
18 Commodity 0.3594 6,950,000 24,978
19 Sales Service Impact 0.3588 24,940
20 Direct Purchase Impact (38)
Large Rate M9
21 Delivery (0.0005) 20,178,000 (111)
22 Commodity 0.3594 20,178,000 72,519
23 Sales Service Impact 0.3588 72,409
24 Direct Purchase Impact (111)
Small Rate T1
25 Direct Purchase Impact (0.0095) 7,537,000 (714)
Average Rate T1
26 Direct Purchase Impact (0.0095) 11,565,938 (1,095)
Large Rate T1
27 Direct Purchase Impact (0.0095) 25,624,080 (2,427)
Small Rate T2
28 Direct Purchase Impact (0.0081) 59,256,000 (4,794)
Average Rate T2
29 Direct Purchase Impact (0.0081) 197,789,850 (16,002)
Large Rate T2
30 Direct Purchase Impact (0.0081) 370,089,000 (29,941)
Large Rate T3
31 Direct Purchase Impact 0.0024 272,712,000 6,572
Notes:
(1)Transportation bill impacts based on monthly demand (m3/d).
Calculation of One-Time Adjustments for Typical Small and Large Customers
ENBRIDGE GAS INC.
Union Rate Zones
Filed: 2024-05-31
EB-2024-0125
Exhibit F
Tab 3
Schedule 5 Page 3 of 3
Page 498
Filed: 2024-05-31
EB-2024-0125
Exhibit G
Tab 1
Page 1 of 3
2023 SCORECARD RESULTS – ENBRIDGE GAS
1. The purpose of the scorecard is to measure and monitor performance of the utility.
The scorecard is produced annually and includes measures in four categories:
customer focus, operational effectiveness, public policy responsiveness, and
financial performance. 2023 is the fifth year that Enbridge Gas is presenting the
scorecard. Enbridge Gas is providing five years of scorecard results (2019 – 2023),
at G, Tab 1, Schedule 1.
2. In 2023, Enbridge Gas met or exceeded all elements of the scorecard except for two
Service Quality Requirements (SQR) measures: Time to Reschedule Missed
Appointment (TRMA) and Meter Reading Performance Metrics (MRPM).
3. In Phase 1 of the Rebasing Application, Enbridge Gas requested a partial exemption
for three SQR measures: TRMA, Call Answering Service Level (CASL), and MRPM.
4. The TRMA tracks the percentage of customers contacted to reschedule work within
two hours of the end of the original appointment time. In Phase 1 of the Rebasing
application Enbridge Gas requested that the TRMA metric be more aligned with the
Distribution System Code (DSC) which requires electric utilities to reschedule
missed appointments within 1 business day of a missed appointment; and
additionally, Enbridge Gas requested that the metric be lowered from 100% to 98%.
In the Phase 1 rebasing Decision and Order, the OEB did lower the target to 98%
however the decision did leave the requirement at 2 hours rather than 1 business
day.1 As outlined in Phase 1 rebasing evidence, Enbridge Gas has taken mitigation
actions2 to improve TRMA results. Enbridge Gas was able to achieve 97.8% for
TRMA in 2023.
1 EB-2022-0200 Decision and Order, December 21, 2023, p. 135.
2 EB-2022-0200 Application and Evidence, Exhibit 1, Tab 7, Schedule 1, p. 19 and Attachment 3.
Page 499
Filed: 2024-05-31
EB-2024-0125
Exhibit G
Tab 1
Page 2 of 3
5. In Phase 1 of the Rebasing Application, Enbridge Gas did apply for a partial
exemption for the CASL measure to align with the DSC. Enbridge Gas was able to
meet this metric in 2022 and 2023 as a result of the mitigation efforts undertaken
from the Company’s mitigation plan.3
6. Meter Reading Performance Measurement (MRPM) measures the percentage of
meters with no read for four consecutive months. As set out in the GDAR, the annual
standard for MRPM is not to exceed 0.5% on an annual basis. The metric does not
consider why Enbridge Gas has not read a meter.
7. In mid-2021, the OEB compliance staff commenced a review of Enbridge Gas' SQR
results following an increased number of customer complaints to the OEB after the
Company’s July 2021 integration of customers to the CIS system. Following the
OEB’s compliance review, Enbridge Gas shared its 2022 MRPM mitigation plan4
with the OEB and as part of an Assurance of Voluntary Compliance (AVC)5,
Enbridge Gas committed to aim for 4% for 2022 (3% when accounting for meters
that Enbridge Gas cannot access). The action taken from mitigation planning in 2022
and 2023 have included additional hiring of meter readers, reduction in attrition,
extended working hours, collaboration with meter reading vendors to conduct regular
performance reviews, process improvements, improved meter reading technology,
and marketing campaigns. Overall, the mitigation measures taken have resulted in a
74% improvement in MRPM results from 2021 to 2023. Enbridge Gas was able to
significantly decrease the number of meters with consecutive estimates and reached
an annual MRPM of 4.1% in 2022 and 1.3% in 2023. Despite significantly improving
this metric, there are persisting challenges beyond Enbridge Gas’ control that limit
the ability for meter readers to access and read a certain portion of gas meters,
impairing the ability to achieve this target.
3 Ibid, and Attachment 2.
4 EB-2022-0200, Exhibit 1, Tab 7, Schedule 1, pp. 18-21; and Attachment 4.
5 EB-2022-0188, EGI-Assurance-of-Voluntary-Compliance-20220912.pdf (oeb.ca)
Page 500
Filed: 2024-05-31
EB-2024-0125
Exhibit G
Tab 1
Page 3 of 3
8. In Phase 2 of the Rebasing Application, Enbridge Gas has proposed that all meters
with access issues caused by or within the control of the customer to address, be
excluded from the MRPM calculation6. Customer behaviour impacting the number of
inaccessible meters includes; locked gates and inside meters that have
unresponsive tenants/landlords, customer sensitivity and obstruction.7 With access
issues removed from the MRPM calculation, Enbridge Gas would have achieved
2.5% in 2022 and 0.7% in 2023. With inaccessible meters removed from the total
unread meters count, Enbridge Gas anticipates that the 2024 MRPM will be between
0.5% and 0.6%. Enbridge Gas continues to make efforts to meet the 0.5% target
however it would be viewed as a stretch target based on the unknown conditions
caused by customer behaviour. For more information on Enbridge Gas’ request to
remove inaccessible meters from the MRPM calculation can be found in the
Company’s Phase 2 Rebasing Application (EB-2024-0111), Exhibit 1, Tab 7,
Schedule 1.
6 EB-2024-0111, Application and Evidence, Exhibit 1, Tab 7, Schedule 1, pp. 5-6.
7 EB-2024-0111, Application and Evidence, Exhibit 1, Tab 7, Schedule 1, pp. 10-13, and Attachment 3.
Page 501
Target Actual Actual Actual Actual Actual
2023
EGI
2022
EGI
2021
EGI
2020
EGI
2019
EGI
#CUSTOMER FOCUS (Service Quality & Customer Satisfaction)
1 85.0%99.3%98.1%96.9%98.9%98.1%
2 85.0%96.3%95.4%94.5%98.8%98.5%
3 75.0%89.5%75.9%64.3%75.2%79.0%
4 80.0%100.0%90.0%100.0%100.0%100.0%
5 331,489 manual checks completed
as per QAP
390,246 manual checks completed
as per QAP
384,858 manual checks completed
as per QAP
427,524 manual checks completed
as per QAP
429,386 manual checks completed
as per QAP
6 10.0%1.4%7.1%16.0%5.4%2.50%
7 98.0%1 97.8%93.8%97.0%97.3%97.0%
OPERATIONAL EFFECTIVENESS (Safety, System Reliability, Asset Management & Cost Control)
8 0.5%1.3%4.1%5.0%4.4%0.7%
9 90.0%95.3%94.1%95.2%96.7%96.7%
10 100.0%100.0%99.7%99.7%99.9%
11 2.10 2.31 1.95 2.22 1.97
12 745.7 683.2 643.9 658.2 653.6
13 19,079.6 17,480.7 16,639.6 16,928.5 16,735.4
14 NA2 N/A3 1,707.5 4 1,632.2 2,075.9
FINANCIAL PERFORMANCE (Financial Ratios)
15 0.92 0.84 0.71 0.66 0.75
16 0.39 0.42 0.41 0.40 0.40
17 0.97 1.10 1.06 1.01 0.98
18 1.75 2.54 2.55 2.34 2.53
19 1.20%2.03%2.07%1.97%2.25%
20 3.00%5.37%5.32%4.96%5.56%
1
2
3
4
Time to Reschedule Missed Appointment target was 100% prior to the Phase 1 Decision
2023 is in draft pending results
2022 results will be available in 2024
2021 results are audited and approved in the DSM Clearance Proceeding
Current Ratio
(Current Assets / Current Liabilities)
Financial Statement Return on Equity
(Net Income / Shareholders' Equity)
Debt Ratio
(Total Debt / Total Assets)
Debt to Equity Ratio
(Total Debt / Shareholders' Equity)
Interest Coverage
(EBIT / Interest Charges)
Financial Statement Return on Assets
(Net Income / Total Assets)
Abandon Rate (# of calls abandon rate)
(# of calls abandoned while waiting for a live agent / # of calls requesting to speak to a live agent)
Time to Reschedule Missed Appointments
(% of rescheduled work within 2 hours of the end of the original appointment time)
Meter Reading Performance
# of meters with no read for 4 consecutive months / # of active meters to be read
% of Emergency Calls Responded within One Hour
(# of emergency calls responded within 60 minutes / # of emergency calls)
Compression Reliability
% reliable for transmission compression
Damages per 1000 locate requests
Total Cost per Customer
($ / Customer)
Total Cost per km of Distribution Pipe
($ / km of Distribution Pipe)
PUBLIC POLICY RESPONSIVENESS (Conservation & Demand Management & Connection of Renewable Generation)
Total Cumulative Cubic Meters of Natural Gas Saved (Net)
(Millions)
Billing accuracy
'The requirement states that utilities should complete manual checks of
their bills to verify data when a meter read demonstrates excessively high or low usage.'
Performance Measure
Reconnection Response Time (# of days to reconnect a customer)
(# of reconnections completed within 2 business days/# of reconnections completed)
Scheduled appointments met on time (appointments met within designated
time period)
(# of appointments met within 4hrs of the scheduled date/# of appointments scheduled in the
month)
Telephone calls answered on time (call answering service level)
(# of calls answered within 30 seconds / # of calls received)
Customer Complaint Written Response (# of days to provide a written response)
# of complaints requiring response within 10 days / # of complaints requiring a written response
EGI OEB SCORECARD 2019 -2023 Filed: 2024-05-31, EB-2024-0125, Exhibit G, Tab 1, Schedule 1, Page 1 of 1
Page 502
2023 IRP Annual Report
1
Integrated Resource
Planning (IRP) —
2023 Annual Report
July 2, 2024
—
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 1 of 97
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SECTION 1 - INTRODUCTION 3
SECTION 2 - IRP INTEGRATION UPDATE 4
SECTION 3 – INTEGRATED RESOURCE PLANNING ALTERNATIVES (IRPAS) EVALUATION AND ASSET
MANAGEMENT PLAN (AMP) UPDATE 5
SECTION 4 – IRP PILOT PLAN UPDATE 12
SECTION 5 - IRP STAKEHOLDER AND INDIGENOUS ENGAGEMENT UPDATE 14
SECTION 6 – NON–PILOT IRP PLAN UPDATES 18
SECTION 7 - INTEGRATED RESOURCE PLANNING ALTERNATIVES UPDATE 20
SECTION 8 - TECHNICAL WORKING GROUP SUMMARY 20
SECTION 9 - DCF+ UPDATE 20
SECTION 10 - IRP PLANNING FOR 2024 22
APPENDIX A: OEB IRP DIRECTIVES AND PROGRESS TOWARDS 2023 PRIORITIES 25
APPENDIX B: INTEGRATED RESOURCE PLANNING ALTERNATIVES 28
APPENDIX C: SUMMARY OF IRP EVALUATIONS 35
APPENDIX D: IRP SCREENING RESULTS FOR LTC PROJECTS 37
APPENDIX E: TECHNICAL WORKING GROUP REPORT 49
APPENDIX F: PILOT FEEDBACK 50
APPENDIX G: IRP ASSESSMENT SCREENING CRITERIA 53
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 2 of 97
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Section 1 – Introduction
This Enbridge Gas Inc. (“Enbridge Gas” or the “Company”) 2023 IRP Annual Report (“Report”) encompasses the period from
January 1, 2023, through to December 31, 2023. This Report complies and is consistent with the Ontario Energy Board (“OEB”)
Integrated Resource Planning (“IRP”) Decision and Order dated July 22, 2021 (“IRP Decision”) establishing an IRP Framework for
Enbridge Gas (“IRP Framework”), where the OEB stated:1
“Enbridge Gas shall file an annual IRP report with the OEB as part of its annual Non-Commodity Deferral Account
Clearance and Earnings Sharing Mechanism application, the proceeding in which it may seek disposition of balances in
the IRP Costs deferral accounts.
The OEB does not intend to approve the annual IRP report, but it could impact the OEB’s findings on the disposition of
amounts in the IRP Costs deferral accounts or inform future proceedings.
The annual IRP report and the report from the IRP Technical Working Group are to be filed for information regardless of
whether Enbridge Gas is seeking approval to clear any balances in the IRP Costs deferral accounts.
The annual IRP report should include the following information:
• A summary of IRP stakeholdering activities from the past year
• A summary of IRP engagement or consultation activities with Indigenous peoples
• Updates on IRP pilot projects underway
• Updates on incorporating IRP into asset management planning
• Updates on status of potential IRP Plans
• Updates on status of approved IRP Plans, including details of adjustments made by Enbridge Gas
• Annual and cumulative summaries of actual peak demand reductions/energy savings generated by each IRP Plan
to-date, including comparisons to the initial forecast reduction/energy savings and the actual amount of
expenditure on each IRP Plan to-date
• The most recent results of Enbridge Gas’s IRP Assessment Process for system needs, including reporting on
those system needs where a negative binary screening or technical/economic evaluation resulted in no further
assessment of IRPAs
• A summary of best available information on demand-side IRPAs, including types of IRPAs, estimates of cost,
peak demand savings, status in Ontario, potential role and relevance to Enbridge Gas’s system, and learnings
from pilot projects and other jurisdictions
• Efforts taken to explore the use of interruptible rates for meeting system needs, including how customers have
been provided the opportunity to consider this option
• Any other IRP-related matters established by the OEB.”
1 EB-2020-0091, OEB Decision and Order, Appendix A, p. 22.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 3 of 97
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Section 2 – IRP Integration Update
In 2023, Enbridge Gas enhanced integration of IRP into its system processes and to date has added 16 IRP resources2, referred to
as full-time equivalents (“FTE”), who are embedded within its asset management and distribution optimization engineering teams as
well as the integrated resource planning, demand side management, financial analysis, regulatory, municipal energy solutions, and
community engagement departments. This is in addition to the 3 FTE IRP roles involved in IRP prior to the IRP Decision.
Incremental work for the Company resulting from the implementation of the IRP Decision includes:
• Binary screening and technical evaluations of facility projects in the Asset Management Plan (“AMP”) and optimization of
the AMP to include IRP Plans;
• Economic analysis of those projects with a technically feasible IRP alternative (“IRPA”);
• Support the technical and economic evaluation of enhanced targeted energy efficiency (“ETEE”) and demand response
(“DR”) IRPAs, as well as design and, once approved, support the delivery and ongoing monitoring and evaluation of IRP
Plans, including IRP Pilot Projects;
• Development and implementation of regional, geo-targeted and pilot-specific IRP stakeholder engagement activities, as
well as an increased level of direct engagement with a number of key IRP stakeholders; and,
• Regulatory support for IRP Plans and for traditional leave to construct (“LTC”) proceedings.
Enbridge Gas built upon the progress from 2022 and continued to enhance cross-functional processes, including the following:
• Integration of the IRP Evaluation Process into the Asset Investment Planning Management (“AIPM”) Process
Enbridge Gas is in the process of integrating the IRP Evaluation Process into the AIPM process through the development
of procedures for introducing Binary Screening into the Solution Planning & Value assessment stage of the AIPM process
as opposed to a distinct IRP evaluation process within the AIPM. This enables investments to be reviewed prior to the
Optimization stage and ensures that investments with IRP potential are reviewed at the earliest stage of the process. In
2023, Enbridge Gas worked through the required protocols and process requirements to enable implementation of the
integration. Implementation and training will be rolled out in 2024 ensuring alignment with key internal stakeholders
involved with the process.
• Refinement of Technical and Economic Evaluation Process for IRPAs
Enbridge Gas refined the technical evaluation process in 2023, including the development of templates used to evaluate
the technical feasibility of investments and to improve the process of gathering, consolidating and documenting inputs from
various teams to support the assessments. This contributed to the streamlined technical evaluation of a total of 698
investments in the EGI Asset Management Plan Addendum - 2024 filed on October 31, 2023. For economic evaluations,
Enbridge Gas has started developing the DCF+ model including identifying the key inputs and assumptions and developing
templates to support the assessment. Further details on the IRP Evaluation are outlined in Section 3.
• Stakeholder Engagement Process
Enbridge Gas developed its internal stakeholder engagement processes associated with the assessment and development
of IRP Plans, including the development of a project plan template which is used to identify the investment scope, cross-
functional project team, and project schedule. Coordination across departments was also further formalized to support
external stakeholder engagement and outreach activities by hosting regular internal stakeholder meetings and though
formal tracking of engagement activities. This ensured alignment and effective processes across departments, and for
engagement opportunities such as conferences, external meetings, webinars, and online promotion of IRP activities. It also
allowed Enbridge Gas to enhance ongoing engagement with key regional stakeholders, such as municipal staff and Local
2 For a description of the roles and responsibilities please see EB-2024-0125, Exhibit C, Tab 1, page 16 – 19.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 4 of 97
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5
Distribution Companies, to share information on the Pilot Projects and served to directly promote the IRP website and
webinar sessions resulting in significant increases in attendance from the spring to fall sessions as outlined in Section 5.
Section 3 – IRPA Evaluation and AMP Update
The 2023 to 2032 AMP was completed in May 2022. Investment project scopes in the capital plan are determined through Enbridge
Gas’ system analysis and optimization of all traditional facility alternatives to meet the forecasted system need in the most cost-
effective manner to ensure the safety, reliability and affordability of the Company’s operations.
From there, investments included in the capital plan advanced through the IRP Evaluation process, as described in EB-2022-0200,
Exhibit 2, Tab 6, Schedule 2, Appendix B (“EB-2022-0200, Appendix B”) (link). Since EB-2022-0200, Appendix B was filed,
additional work has been completed to continue to evaluate investments in the 2023 to 2032 capital plan. Enbridge Gas continues
to refine the systematic and forward-looking IRP Assessment process detailed below.
1. Initial Screening
The evaluation process began with removing non-gas-carrying asset investments from the list of 2023-2032 AMP
investments that would proceed to the binary screening phase.
2. Binary Screening
Investments are screened out as per Section 5.2 of the IRP Framework. Investments with the Asset Class of Customer
Connections will also be included in the list of Binary Screening requirements. This was reviewed with the TWG in May 2023.
3. Technical Screening & Evaluation
Investments undergo an initial technical screening to determine whether a detailed technical evaluation is required. Further
details on this technical screening process can be found in Appendix G.
To evaluate whether an investment could have technically feasible IRPAs, Enbridge Gas determined which AMP investment
categories the Company considered to be driven in part, or in full, by design hour/day demand. This includes projects with
the asset class of “growth”, “distribution pipeline”, or “distribution station”. Enbridge Gas then determined the level of design
hour/day demand reduction required to meet a system need by calculating the total customer design hour/day demand for
natural gas and the total current design hour/day capacity; the difference between these two factors determined the design
hour/day demand capacity required to meet the system needs. Energy transition adjustments are taken into consideration
as part of the demand forecasting process, as noted below. Enbridge Gas then assessed the technical potential of IRPAs to
meet a system need. Where IRPAs have a technical potential to reduce the design hour/day demand reduction without
compromising the safety and reliability of the system, these investments will pass the technical evaluation.
4. Economic Evaluation
Investments that have passed technical evaluation will be evaluated economically to compare the IRPAs to the baseline
facility alternative through the Discounted Cash Flow-plus (“DCF+”) test. The DCF+ results for the IRPAs and the baseline
facility alternative will be compared to one another to determine the optimal alternative or combination of alternatives to meet
the system need. Investments that have passed the economic evaluation with an optimal alternative that is inclusive of one
or more IRPAs will be reviewed and selected for IRPA Plan Development.
See Section 9 for updates on the DCF+ test that will be used for economic evaluations. Also see Section 6 for Non–Pilot
IRP Plan Updates.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 5 of 97
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6
The current IRP screening and evaluation process is outlined in Figure 3.1.
Figure 3-1 – IRP Evaluation Process
2023 IRP Evaluation Updates
Enbridge Gas filed an update to EB-2022-0200, Appendix B on March 8 and October 31, 2023, to provide the latest results of
Enbridge Gas’s IRP Evaluation Process. This included reporting on those system needs where a negative binary screening,
technical or economic evaluation resulted in no further assessment of IRPAs. Enbridge Gas will continue to evaluate investment
project scopes and timing to allow for appropriate prioritization and resource allocation in the IRP evaluation process, to ensure
assessments are completed on all projects where an IRPA would be feasible for implementation.
A summary of the process is provided below.
• March 8, 2023 – EB-2022-0200, Appendix B (updated March 8, 2023) (link)
o Enbridge Gas completed the technical feasibility process for 552 projects as of March 8, 2023.
• Between March 8 and October 31, 2023 – Enbridge Gas continued to prioritize completing IRP technical evaluations for
growth driven investments and targeted the completion of technical evaluations of both the remaining growth investments
from the 2023 – 2032 AMP and new growth driven investments.
o Investments that passed the technical evaluation and had a relatively small project scope and small project cost (less
than $500,000) were deprioritized for economic evaluation and categorized as “Low Cost, Low Value”. These facility
projects were categorized in this manner as their project scope and cost are relatively small in nature and therefore
may have minimal IRP potential. The ongoing approach to Low Cost, Low Value projects will be discussed with the
IRP TWG in 2024.
Any remaining non-growth investments that had not yet had a technical evaluation, except for select investments such
as select Distribution Pipe investments that were straightforward to assess as the project scope was able to be
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 6 of 97
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7
downsized to the smallest pipe size without compromising system reliability prior to IRPA consideration, had their IRP
technical evaluation deferred to 2024. This approach was taken to prioritize the evaluation of growth projects, which
were determined to have higher IRP potential than non-growth investments based on the supply-side and demand-
side technical evaluations that had been completed to-date.
• October 31, 2023 – Enbridge Gas filed the Asset Management Plan Addendum – 2024 under EB-2020-0091 which
included an updated version of the previously filed Appendix B on March 8, 2023 at EB-2022-0200. This updated Appendix
B filed on October 31, 2023 included the original 3,087 investments as well as 1,194 new investments to Appendix B.
o 949 investments were deemed not subject to any IRP process because they related to non-gas carrying
investments.
o 2,296 investments were screened out using binary screening
o 698 investments had undergone a complete technical evaluation at the time of the filing.
632 of the 698 investments are from the Original Appendix B investments, and 63 had passed the
evaluation, exclusive of the two pilot project investments
66 of the 698 investments are from the New investments to Appendix, and none had passed the
evaluation.
o 338 investments remain to undergo technical evaluation or had the evaluation currently in progress as of the time
of filing.
67 of these 338 investments under the Asset Class of Growth
• 43 of these 67 investments are from the Original Appendix B investments
• 24 of the 67 investments are from the New investments to Appendix B
• Technical evaluation of these investments were paused in October 2023 pending the planned
System Reinforcement Plan 2024 update and impacts to the investment project scopes.
5 of the 338 investments under the Asset Class of Transmission Pipe & Underground Storage will have
options assessed prior to the Leave to Construct (“LTC”) application.
257 investments under the Asset Class of Distribution Pipe and Distribution Station have an IRP
evaluation status of “On Hold”. These investments will be re-evaluated annually for project scope and
timing updates to allow for appropriate resource allocation for the IRP evaluation process. Once the
detailed project scope is confirmed, these investments proceed through the IRP evaluation process. EGI
is also looking to assess if any of these investments could be grouped and targeted with a regional
IRPA Plan.
9 investments in the Enhanced Distribution Integrity Management Program have a technical evaluation
status of “In Progress” and are awaiting further integrity assessment to confirm project scope and timing.
The IRP evaluation will proceed once project scope and timing has been established.
For the 698 investments that had undergone a complete technical evaluation at the time the Asset Management Plan Addendum –
2024 was filed October 31, 2023 under EB-2020-0091 noted above, exclusive of the 2 pilot project investments, Enbridge Gas has
provided a high-level breakdown of the technical evaluation comments categories that can be found in Appendix B of the Asset
Management Plan Addendum - 2024, cumulative capital expenditure for the projects, and number of related investments in the
tables below as follows:
• Investments that did not pass the technical screening stage are included in Table 3.13
• Investments that did not pass the technical evaluation stage are included in Table 3.23
• Investments that did pass the technical evaluation stage are included in Table 3.3
As Enbridge Gas progressed to the Technical Evaluation stage of the IRP framework for determining the technical viability of IRPAs
to eliminate, reduce or defer the investment project scope, review of investment project scopes indicated that not all investments
3 Appendix G, Table 1 outlines investment categories which did not pass the technical screening and evaluation stage.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 7 of 97
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passing Binary Screening would require a detailed technical evaluation due to the nature of the project scope. A detailed technical
evaluation involves network modelling of customer demands and demand reductions required to meet system needs. This rigorous
and time intensive process would not be applicable to investment categories outlined in Table 3.1 as outlined in the detailed
category descriptions provided in Appendix G, Table 1.
Thus, the “Technical Evaluation” stage of the IRP Evaluation process was updated to “Technical Screening and Evaluation” as
shown in Figure 3-1. Enbridge Gas has discussed and reviewed the Technical Screening and Evaluation Process with the TWG to
obtain feedback and will continue to engage with the TWG for further improvement and refinement of the IRP Evaluation Process.
The category in Table 3.1 with the highest capital costs is “Additional Screening for Investment descriptions where IRPAs are not
applicable”. This category is comprised of multiple different subcategories of investments where IRPAs would not be applicable,
primarily due to the programmatic nature of the investments which are integrity related as opposed to individually distinct projects.
While the Binary Screening stage includes a screening criterion for Pipeline and Relocation Projects that are below a $2 M
threshold, programmatic spend on essential integrity related programs with annual spend greater than $2 M pass the Binary
Screening stage however they do not have applicable IRPAs that could defer, reduce, or eliminate the investment scope due to the
nature of the work.
Examples of these subcategories are listed below:
o AMP Fitting
o Class Location
o Corrosion
o Farm Taps
o Facilities Integrity Management Program
o Fire Suppression
o Geohazard
o Independent Asset Integrity Review (IAIR)
o Integrity Retrofit
o Inside Room Regulators
o Low Pressure Delivery Meter Sets (LPDMS)
o Meter Exchanges
o Maximum Operating Pressure (MOP verification)
o Pressure Factoring Metering (PFM Program)
o Remote Terminal Units
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 8 of 97
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Table 3.1 – Breakdown of Investments Technically Screened out of the 2023-2032 AMP
Category 2023-2032 Forecast (Includes
overhead allocation)
# of
Investments
NPS 2, cannot downsize or retire $98.5 M 35
Compression Station related projects are required to maintain existing
deliverability and throughput. This is necessary to maintain security of supply
and stable natural gas pricing during supply disruptions.
$233.9 M 15
Storage Pools & Well related projects are required to maintain existing
deliverability and throughput. This is necessary to maintain security of supply
and stable natural gas pricing during supply disruptions.
$45.5 M 9
Customer Connection-related projects are required to serve new customers
connected in accordance with guidelines of EBO 188. The OEB concluded
that as part of the first-generation IRP Framework it is not appropriate to
provide funding to Enbridge Gas for electricity IRPAs.
$2,409.6 M 65
Hydrogen related projects are required as no IRPAs can replace the hydrogen
feasibility assessments and hydrogen blending initiatives.
$26.3 M 4
Distribution station condition related, IRPA not applicable $202.6 M 68
Additional Screening for Investment descriptions where IRPAs are not
applicable
$4,351.5 M 280
Project Status/Timing Related $778.7 M 79
Grand Total $8,146.6 M 555
Table 3.2 – Breakdown of Investments Technically Evaluated out of the 2023-2032 AMP
Category 2023-2032 Forecast (Includes
overhead allocation)
# of
Investments
Potential project scope could be replaced with NPS 2. IRPAs not applicable
and scope to be confirmed when project enters the detailed design phase.
• Where applicable - It is recommended to maintain pipe size for trunk
mains or system resiliency
$243.5 M 76
Other – Miscellaneous $15.3 M 2
Grand Total $258.8 M 78
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 9 of 97
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Table 3.3 – Breakdown of Investments Passing Technical Evaluation of the 2023-2032 AMP
Category 2023-2032 Forecast (Includes
overhead allocation)
# of
Investments
Investments passing technical evaluation $61.6 M 26
Investments passing technical evaluation - Low cost, Low value $5.4 M 37
Grand Total $67.0 M 63
Enbridge Gas is continually evolving its system models to improve the modelling methodology. This continuous evolution includes
gathering and considering newly available and relevant information, data, and insights. This ensures that Enbridge Gas’s system
models reflect the best available information regarding Ontario’s projected future demand of natural gas. This includes gathering
and considering any energy transition related plans, policies, or regulations.
Since the update to the information previously filed at EB-2022-0200, Appendix B (filed October 31, 2023) there are 3 key factors
that must be considered, as they could have an impact on the 10-year forecast, and subsequently the list of projects that would form
a future version of Appendix B.
1. System Reinforcement Plan (“SRP”) Update
o A refresh to the SRP was completed in Q1 2024. The process included an update to the customer connection
forecast, updates to customer load, new connection and new proposals with actuals, and updated customer load
values for new customers. Due to these updates, a number of the growth projects have shifted in timing or scope,
which will be reflected in the next AMP to be filed in the fall of 2024.
2. Energy Transition (“ET”) Adjustments
o As summarized in Enbridge Gas’s 2024 Rates Application (EB-2022-0200), Enbridge Gas introduced ET Adjustments
to its demand forecasts (for existing customers, customer additions and average annual use) and design elements
(design hour and design day) to account for potential changes to natural gas demand in the 10-year forecast period.
These demand forecasts and design elements are routinely used in various business planning processes such as the
SRP, AMP, Gas Supply Plan, etc. The ET Adjustments are based on external factors related to policy signals
(federal/provincial/municipal), market trends (builder and consumer preferences) and stakeholder feedback (customer,
municipal and Indigenous). Annually Enbridge Gas will review, and update as needed, the ET Adjustments and
account for new and/or updated external signals and/or development. A summary of the ET Adjustments will be
provided in the AMP to be filed in the fall of 2024.
3. OEB Decision on Enbridge Gas’s 2024 Rates Application – Phase 1 (EB-2022-0200) (“2024 Rebasing Phase 1 Decision”)
o Cost optimization of the 10-year plan is required as the OEB’s 2024 Rebasing Phase 1 Decision did not accept the
AMP as filed and ordered a reduction in the capital budget. Reductions to the 2024 capital budget were reflected and
filed in the Phase 1 Draft Rate Order4. Further details on the 10-year capital plan will be reflected in the AMP to be
filed in the fall of 2024.
Due to the changes and time required to determine the impacts of these three factors on the 10-year forecast, Enbridge Gas
paused the IRP technical evaluation of the remaining growth and Enhanced Distribution Integrity Management Program
investments as of October 2023. Enbridge has restarted the technical evaluation process as of May 2024 following incorporation of
the SRP Update and ET adjustments in the 10-year capital forecast with an initial focus on prioritizing the evaluation of growth
4 EB-2022-0200, Rate Order, Working Papers, Schedule 5, p.1. (February 16, 2024)
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 10 of 97
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projects. Enhanced Distribution Integrity Management Program related investments will undergo IRP evaluation upon the
completion of the integrity assessment and determination of potential scope impacts.
The most current version of the information previously filed at EB-2022-0200, Appendix B is the version as filed under EB-2020-
0091 on October 31, 2023. The 10-year forecast that will incorporate the above factors, directly or via sensitivities, as well as the
associated details is anticipated to be filed with the 2025-2034 AMP in October 2024.
In lieu of providing the same information provided at Appendix B as filed under EB-2020-0091 on October 31, 2023, the updated
status of a subset of investments that were both prioritized for IRP assessment and that passed the technical evaluation are
summarized in Appendix C. This subset includes the list of 28 investments that were in the 2023-2032 10-year forecast filed on
October 31, 2023, prior to the SRP update, which had both passed the technical evaluation and were not flagged as Low Cost, Low
Value in 2023. These 28 investments also included the two IRP Pilot Project investments. Understanding the impacts of the
subsequent SRP update and the ET Adjustments on the 28 investments, which include the baseline facility investments for the 2
pilot projects, was prioritized and the impacts have been included as part of Appendix C.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 11 of 97
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Section 4 – IRP Pilot Projects Update
The development of the IRP Pilot Projects was initiated in 2022, where Parry Sound and Southern Lake Huron were selected as the
two pilot locations. Details on the identified objectives, selection process and the initial scoping of the pilot projects can be found in
the 2022 IRP Annual Report.5
In 2023, Enbridge Gas continued the development of the IRP Pilot Projects application for the two selected pilot locations. Key
elements of the application, including the scope of the ETEE and DR program, as well as deployment of hourly measurement, were
discussed with the Technical Working Group (“TWG”). Additionally, draft evidence was provided to the TWG for review and
comment, which Enbridge Gas then incorporated into final evidence as it considered appropriate. In each of the pilot areas,
Enbridge Gas initiated stakeholder engagement in Q4 2022 with representatives of the municipalities, local electric distribution
companies (“LDC”), Hydro One and the Independent Electricity System Operator (“IESO”). Engagement sessions continued into
2023 where Enbridge Gas provided a high-level overview of the IRP Pilot Projects and sought input to confirm the forecasted
system needs where appropriate.
Additionally, community-level engagement was initiated through in-person open house sessions in each of the pilot areas to provide
an overview of the IRP Pilot Projects and collect feedback from the public. These sessions were promoted online via email and
through the local newspaper and Facebook advertisements. The materials for the open house are available on the IRP Pilot
Projects webpage.6
Following the stakeholder discussions and community engagement events, Enbridge Gas provided a presentation on the IRP Pilot
Projects at the respective council meetings, including the Town of Parry Sound, County of Lambton and the Town of Plympton-
Wyoming. A resolution was passed for all three councils that indicated Council’s support for the IRP Pilot Project in their community,
and letters of support were received.
A single application for both IRP Pilot Projects was filed with the OEB on July 19, 20237, under EB-2022-0335 (link). The application
sought approval of the cost consequences of the two IRP Pilot Projects, including approval to record the associated costs in the IRP
costs deferral accounts. The application included details on the project area and need, baseline facility alternatives, design of
IRPAs, associated budget and evaluation plans, an illustrative Stage 1 DCF test, and stakeholder engagement.
In response to NRCan’s decision to close the application process for new entrants into the Greener Homes Grant program in Q1
2024, Enbridge Gas filed updated evidence on December 21, 20238.
In response to the changes to the 10-year capital forecast resulting from the factors noted in Section 3, Enbridge Gas consulted with
the TWG in April 2024 regarding whether there was a need to update the IRP Pilot Projects evidence. This process resulted in
Enbridge Gas determining it was appropriate to move forward with the Southern Lake Huron Pilot Project focused solely on
demand-side alternatives, and the Parry Sound Pilot Project focused solely on the supply-side alternative as outlined in the letter
filed with the OEB April 30, 20249. The TWG was generally supportive of this approach.
In the course of the May 2024 energy transition and demand forecast adjustment updates, Enbridge Gas applied best available
information to the Company’s 10-year demand forecast and determined that the baseline facility projects for the Parry Sound Pilot
Project have been pushed out of the Company’s 10-year capital forecast. Without a justifiable need for localized CNG injection
within the Parry Sound area, it was no longer reasonable to proceed with the Parry Sound Pilot Project. Enbridge Gas informed the
TWG and subsequently notified the OEB in the letter filed June 7, 202410. The updated Pilot Project application and evidence was
filed with the OEB June 28, 2024.
5 Link to 2022 IRP Annual Report, Section 4, page 5-9. 6 Link to Parry Sound Pilot Project webpage; Link to Southern Lake Huron Pilot Project webpage. 7 Enbridge Gas Inc., Integrated Resource Planning Pilot Projects Application and Evidence (EB-2022-0335), July 19, 2023. 8 Enbridge Gas Inc., Integrated Resource Planning Pilot Projects Updated Evidence (EB-2022-0335), December 21, 2023.
9 Enbridge Gas Inc., Integrated Resource Planning Pilot Projects Application Status Update, April 30, 2024 10 Enbridge Gas Inc., Integrated Resource Planning Pilot Projects Application Status Update, June 7, 2024
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 12 of 97
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The regulatory process to date for the IRP Pilot Projects (EB-2022-0335), including developments in 2024, includes:
• September 8, 2023 – OEB issued Procedural Order (“PO”) No. 1 approving intervenor requests and detailing the timelines
for subsequent procedural steps.
• September 14, 2023 – OEB staff filed a proposed issues list for the proceeding.
• September 21, 2023 – Intervenors and Enbridge Gas filed submissions on the proposed issues list for the proceeding.
• September 26, 2023 – Intervenors and Enbridge Gas filed reply submissions on the issues proposed. Additionally,
Enbridge Gas also filed a request to defer interrogatory submissions and interrogatory response submissions by one week,
to ensure that witnesses participating in the OEB’s oral hearing for the Company’s Panhandle Regional Expansion Project
leave to construct application were available to contribute to the development of interrogatory responses.
• October 6, 2023 – OEB issued PO No. 2 which includes a Decision on the Issue List for the proceeding and approval of
Enbridge Gas’s request for a deferral of interrogatory submissions and responses by one week, thereby adjusting the
procedural timelines set out in PO No. 1.
• October 20, 2023 – OEB staff and intervenors filed written interrogatories.
• November 3, 2023 – Enbridge Gas filed written responses to OEB staff and intervenor interrogatories.
• November 8, 2023 – OEB staff and intervenors filed comments regarding the need for a technical conference.
• November 10, 2023 – Enbridge Gas filed comments regarding the need for a technical conference. Additionally, Enbridge
Gas advised the OEB that Natural Resources Canada (“NRCan”) informed Enbridge Gas that it is halting intake into the
Canada Greener Homes Grant program in Q1 2024, thereby impacting the Home Efficiency Rebate Plus (“HER+”)
program delivered by Enbridge Gas, and subsequently the design and budget of the IRP Pilot Projects. Enbridge Gas
noted it planned to file all necessary evidence updates resulting from the NRCan announcement.
• November 17, 2023 – OEB issued PO No. 3 determining that the revised (updated) proposal for the IRP Pilot Projects
should maintain the inclusion of electric heat pumps and should consider alternative approaches to address the loss of
NRCan incentives. The OEB also determined a technical conference is warranted and placed the application in abeyance
pending the filing of updated evidence and interrogatory responses by Enbridge Gas.
• December 22, 2023 – Pursuant to PO No. 3 Enbridge Gas filed updates to its pre-filed evidence and interrogatory responses.
• January 12, 2024 – Enbridge Gas filed a letter requesting the application remain in abeyance to allow time for Enbridge
Gas to assess the impacts (if any) of the OEB’s 2024 Rebasing Phase 1 Decision (EB-2022-0200).
• February 29, 2024 – Enbridge Gas filed a letter requesting the application remain in abeyance until April 30.
• March 12, 2024 – OEB issued a letter citing concerns for the delay and requested Enbridge Gas explain the delay and next
steps.
• March 26, 2024 – Enbridge Gas filed a response providing insight into the delay and requesting that the application remain
in abeyance until April 30 to allow time to engage the Technical Working Group.
• April 30, 2024 – Enbridge Gas filed a response providing a summary of the proposed IRP Pilot Project scope changes and
anticipated timing to update the evidence by June 28, 2024.
• June 7, 2024 – Enbridge Gas filed a status update letter stating that the Parry Sound baseline facility projects are no
longer in the 10-year capital forecast, and it was therefore no longer reasonable to include the Parry Sound Pilot Project in
the updated application.
• June 28, 2024 - Enbridge Gas filed updates to its pre-filed evidence and interrogatory responses.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 13 of 97
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Section 5 – IRP Stakeholder and Indigenous Engagement Update
As part of the OEB’s IRP Decision, the OEB determined that “the components of Enbridge Gas’s proposed Stakeholder
Engagement Process will provide valuable input into Enbridge Gas’s IRP activities and shall be incorporated in the IRP Framework.
The OEB also directs the establishment of a website by Enbridge Gas to facilitate the broad sharing of information on IRP
stakeholder efforts.”11
Regional Engagement
Enbridge Gas held its first regional engagement sessions beginning in April 2023. The company hosted hour-long webinars for each
of its seven operating regions. Topics included the foundations of Enbridge Gas's energy transition efforts, including the revised
Pathways study, as well as an introduction of IRP and Enbridge Gas’s non-pipes planning efforts and information on the IRP Pilot
Projects in the Northern and Southwest regions.
A second round of sessions were held at the end of November 2023 to provide up-to-date information on the AMP. Based on
feedback received from its Spring 2023 sessions, Enbridge Gas included information on its assessment criteria and technical
evaluation process, EDIMP, IRP Pilot Projects updates, overview of how projects move through internal review and a summary of
projects from the AMP located within each of the respective regions. The sessions concluded with a Question and Answer session
and details on how to stay engaged and share feedback via the sustainability webpage and IRP mailbox.
To increase attendance from the spring to fall sessions Enbridge Gas attempted a range of promotional activities, including online
advertisements via Facebook and Instagram (as shown in Figure 5.1 below), but found direct engagement through IRP staff
outreach to be the most effective at driving participation. Enbridge Gas also developed promotional materials for engagement at live
events including the Association of Municipalities of Ontario (“AMO”) conference in August 2023, the Federation of Northern Ontario
Municipalities (“FONOM”) conference in May 2023, and the Rural Ontario Municipal Association (“ROMA”) conference in January
2023. Those that had registered on the website for updates were sent a newsletter in early November 2023 outlining the webinar
schedule as well as providing an overview of IRP activities. These efforts resulted in significant increases in attendance and
feedback (outlined in Figure 5.2 below).
Figure 5.1 – Example of the Online Webinar Promotion
11 EB-2020-0091, OEB Decision and Order, p. 66.
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Figure 5.2 – Regional Webinar Attendance Figures
During each session, attendees were encouraged to view the webpage for more information and were automatically registered to
receive email updates on project information, page updates, and upcoming newsletters. The feedback shared has been collected
and shared on the website via the FAQ section and the “What We’ve Heard”12 tabs included on the pilot pages.
Enbridge Gas notes that the regional engagement sessions are not the appropriate forum to discuss government climate policies
that should (or should not) be adopted. Thus, comments and feedback considered out of scope for IRP Pilot Projects information
sessions have not been shared.
Municipal Outreach
Enbridge Gas continued to focus on stakeholder engagement efforts with municipalities. Enbridge Gas participated in the following
conferences in 2023; ROMA conference in January 2023, the FONOM conference in May 2023, and the AMO conference in August
2023. The conferences were leveraged as an opportunity to raise awareness among municipalities about natural gas IRP and how
they can be further involved in the regional planning process. An example of the materials provided to conference participants is
provided in Figure 5.3 below.
Figure 5.3 – Example of Information Shared with Participants
12 Southern Lake Huron Pilot Page, Parry Sound Pilot Page
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 15 of 97
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Enbridge Gas also continues to work directly with municipalities to understand the impact of their community energy plans on the
Company’s demand forecasts and system planning. Enbridge Gas has expanded its municipal engagement efforts to include the
coordinated interplay between the Energy Transition team and other internal stakeholder management groups including Municipal
Energy Solutions and Municipal Affairs, amongst other internal groups. This included targeted engagement of the regions involved
with the potential Owen Sound Reinforcement Project and with municipal stakeholders in the Ottawa region, which focused on
Enbridge Gas Ottawa-area projects, pipeline integrity updates, Enbridge’s Demand Forecast Assumptions and IRP at Enbridge
Gas. As part of its municipal engagement efforts, Enbridge Gas will continue discussions with other priority municipalities as
projects are identified.
Enbridge Gas’s participation in the Regional Planning Process Advisory Group (“RPPAG”), which looks specifically at electricity
planning in the province, is aligned with this ongoing work. As part of the RPPAG process, a subgroup was formed to develop a
document that could help electric utilities interpret and allow community energy plans to be considered in the electricity planning
processes. Enbridge Gas developed a similar internal document to gather similar natural gas-focused metrics to aid in Enbridge
Gas’s demand forecast and system planning.13
IRP Web Content
In December 2021, the Enbridge Gas IRP Regional Planning and Engagement webpage went live.14 The webpage allows
individuals to learn about Enbridge Gas’s IRP activities and to register for email updates on stakeholder engagement sessions in
their region. The registration process is quick and allows for the registration of multiple regions. By registering an email address with
Enbridge Gas, individuals give permission to receive emails from the Company in the future, which meets the requirements of
Canada's Anti-Spam Legislation (“CASL”). In early 2023 the IRP website was updated to provide information on the IRP Pilots in the
Parry Sound15 and Southern Lake Huron16 areas.
Throughout 2023, Enbridge Gas continued to develop its website content to include information about the pilot projects in Parry
Sound and Southern Lake Huron with specific pages and materials outlining the efforts taken and the potential impacts to the
community. The pilot project webpages include maps of the target areas, links to regulatory updates and an opportunity to review
and share feedback with Enbridge Gas. On the main page, an FAQ section was introduced to share common feedback Enbridge
Gas has received across its various engagement efforts. Pilot feedback can be found here: Southern Lake Huron and Parry Sound
The IRP website will continue to be the primary source of information including dates for regional engagement sessions, IRP pilot
webinars, and information on how to sign up and participate. Enbridge Gas conducted a social media campaign to promote the
website and drive sign-ups for webinars (see Figure 5.4 below). Between the two posted ads there were over 80,000 views resulting
in 481 hits on the landing page, and 374 post reactions.
13 The RPPAG-reviewed Municipal Information document can be found on the OEB web site: https://www.oeb.ca/consultations-and-projects/policy-initiatives-and-consultations/regional-planning-process-review#municipal 14 Regional Planning & Engagement | Enbridge Gas
15 Parry Sound Project - Regional Planning & Engagement | Enbridge Gas 16 Southern Lake Huron Project - Regional Planning & Engagement | Enbridge Gas
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 16 of 97
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Figure 5.4 – Example of the Social Media Campaign to Highlight the IRP webpage
Indigenous Engagement
IRP has continued to support the Indigenous Engagement team with informational materials for use during informal discussions,
and during their normal course of engagements to highlight the Regional Engagement sessions and to promote registrations for
engagement events that may be happening in their areas. In 2023, the OEB developed an Indigenous Working group where
Enbridge Gas has engaged on a range of topics including energy transition. Enbridge Gas has proposed to provide IRP updates to
the Indigenous Working Group. Enbridge Gas has included IRP content in its “Eastern” regional newsletters in Q3 and Q4 that are
shared with the consultation departments at a wide range of First Nations groups. These newsletters included an introduction to
IRPAs, an outline of the IRP process, and links to the IRP main page. These channels will continue to be leveraged to communicate
and share more IRP content into 2024.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 17 of 97
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Section 6 – Non–Pilot IRP Plan Updates
As Enbridge Gas completes the IRP Evaluation process for investments in the capital plan, IRP Plans will be developed for projects
with technically and economically feasible IRPAs, where the IRPA is determined to be the preferred alternative to address a system
need. This section provides an update on the status of IRP Plans in-flight and in development in 2023.
In 2023, Enbridge Gas did not file any non-Pilot IRP Plan applications with the OEB, however, Enbridge Gas continued with the
implementation of an IRPA for the Kingston Reinforcement Project and began development of an IRP Plan in the Owen Sound
area.
Kingston Reinforcement Project
The East Kingston Creekford Rd Reinforcement project was a planned capital reinforcement, and Enbridge Gas determined that
this project could be deferred by implementing a supply side IRPA in the form of CNG beginning in 2022. As CNG can be quickly
injected into the natural gas system once the proper modifications have been made and a CNG trailer is secured, it ensured near-
term system constraints could be addressed while other IRPAs were considered. Without the CNG injection, the Kingston system
was anticipated to fall below its minimum pressure requirements as early as the Winter of 2022/2023. Given the urgency of the
near-term constraint and need, Enbridge Gas did not wait to implement the CNG alternative and CNG was procured for the winters
of 2022/2023 and 2023/2024. The CNG agreement provided time for Enbridge Gas to implement a Contract turnback to reduce
contract demand avoiding the facilities project. The turnback provided 2,200 m3/hour and was confirmed by the Contract Customer
on November 11, 2022. This capacity was sufficient to defer the reinforcement; however, it was not received in time to avoid a CNG
contract back-up solution. 17
As part of the 2022 Utility Earnings and Disposition of Deferral & Variance Account Balances Settlement Proposal, parties agreed
that it was appropriate for Enbridge Gas to clear the balances as requested for clearance18 for the supply-side CNG IRPA for the
East Kingston Creekford Rd reinforcement project.19 OEB Staff submitted that enabling Enbridge Gas to record project costs of this
nature in the IRP deferral accounts without an IRP Plan approval supports the OEB’s intent for Enbridge Gas to give greater
consideration to IRP alternatives, and also promotes administration efficiency, enabling Enbridge Gas to pursue smaller IRP
projects without seeking an IRP Plan approval.20 The Settlement Proposal was approved as filed.21
Enbridge Gas is seeking recovery of the ongoing 2023 CNG IRPA costs in the 2023 Utility Earnings and Disposition of Deferral &
Variance Account Balances (EB-2024-0125). The system will be reviewed and monitored routinely to understand if there are any
changes to the system need, and to re-evaluate whether technical and economic feasible IRPAs can be implemented.
Owen Sound Reinforcement Project
The Owen Sound County Rd 40 reinforcement is a 12km NPS 12 4,670 kPa project, continuation of the Phase 4 loop reinforcement
along the existing Owen Sound lateral, with a project in-service date of 2025 (Investment #30542). The primary driver of the project
is growth. Enbridge Gas reviewed this project for IRPAs including:
- Supply-side alternatives: CNG
17 EB-2023-0092, Exhibit C, Tab 1, Page 20 – 25 (Filed June 14, 2023). 18 EB-2023-0092, Exhibit N1, Tab 1, Schedule 1, Page 7 (filed November 28, 2023). 19 Also see EB-2023-0092, Exhibit N1, Tab 1, Schedule 1, pp. 10-11: “There was a small amount ($2,860) included in the 2022 IRP Operating Costs Deferral Account related to foregone revenue from a customer who turned back capacity as part of an IRP project in Kingston. Parties did not agree on the clearance of this part of the account balance. Instead, parties agreed that this amount will be carried forward to the 2023 account.” Also see EB-2024-0125, Exhibit C, Tab 1, p. 20: “Enbridge Gas is no longer seeking recovery of the lost revenue associated with the contract demand reduction for this project.”
20 EB-2023-0092, OEB Staff Submission on Settlement Proposal, page 6. 21 EB-2023-0092, Decision and Order, page 4.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 18 of 97
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- Demand-side alternatives: ETEE, DR, and contract & interruptible rates review
In each municipality located downstream of the reinforcement project, Enbridge Gas initiated stakeholder engagement sessions in
October and November 2023 with representatives of the municipalities, electric LDCs, Hydro One and the IESO to allow Enbridge
Gas to provide a high-level overview of the project and seek input on the forecasted system growth and demands within their
region. This included the Municipality of Grey County, City of Owen Sound, Municipality of Meaford, Town of the Blue Mountains,
Township of Georgian Bluffs, Bruce County, Town of Saugeen Shores, Municipality of Arran Elderslie, and Town of South Bruce
Peninsula.
Enbridge Gas implemented an In-Franchise Binding Reverse Open season, which offered contract customers within the proposed
project service area an opportunity to “turnback” or reduce their existing contracted capacity. No responses were received.
The analysis of the IRPAs indicated that CNG was a viable option in deferring the project by a minimum of five years. A project
team was assembled to begin the development of the IRP Plan and to review the scope of the CNG IRPA in greater detail.
As a result of the SRP update, as noted in Section 3, the timing of the Owen Sound project has shifted from 2025 to 2031 and the
development of the IRP Plan for this project has been put on hold. The project will be reviewed and monitored routinely to
understand if there are any changes to the system need, and to re-evaluate whether technical and economic feasible IRPAs can be
implemented.
The revised in-service dates of project(s) mentioned in this section are included in Appendix C informed by the impacts to the 10-
year capital forecast as a result of the key factors discussed in Section 3.
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Section 7 – Integrated Resource Planning Alternatives Update
In its Decision and Order establishing an IRP Framework for Enbridge Gas, the OEB found that a “...document on best available
information for demand-side alternatives would promote more timely development of IRP Plans and directs Enbridge Gas to include
a listing in its annual IRP Report.”22
Appendix B: Integrated Resource Planning Alternatives lists the integrated resource planning alternatives and includes information
on these specific IRPAs as suggested by OEB Staff including “types of IRPAs, estimates of cost, peak demand savings, status in
Ontario, the potential role and relevance to Enbridge Gas’s system, and learnings from pilot projects and other jurisdictions.”
Enbridge Gas also expects the IRPA pilot projects to provide more information allowing for refinement and updating of the impacts
of some of the IRPAs listed.
Section 8 – Technical Working Group Summary
In the IRP Decision, the OEB directed that an IRP Technical Working Group be established and led by OEB staff, to provide input on
IRP issues that will be of value to both Enbridge Gas in implementing IRP, and to the OEB in its oversight of the IRP Framework.
All documents and presentations concerning the IRP Technical working group can be found on the OEB website.23
Attached in Appendix E: Technical Working Group Report is a report prepared by the IRP Technical Working Group
Section 9 – DCF+ Update
In the IRP Decision, the OEB concluded that the DCF+ test should be the economic evaluation test used under the IRP Framework.
Further, the OEB recognizes that the DCF+ test could be improved to better identify and define the costs and benefits of Facility
Alternatives and IRPAs and clarify how these costs and benefits should be considered within the DCF+ test. The OEB directed
Enbridge Gas to study improvements to the DCF+ test for IRP and encouraged consultation with the TWG, which includes
representatives from Enbridge Gas, OEB staff, and non-utility members.24
In 2022, Enbridge Gas engaged Guidehouse to develop recommendations on how the DCF+ test could be improved to better identify
and define the costs and benefits of traditional pipeline infrastructure and supply-side and demand-side IRP solutions.
Enbridge Gas consulted with the TWG throughout 2023 to consider enhancements to the DCF+ test. The DCF+ test was discussed
at seven TWG meetings in 202325, including two secondary meetings of the DCF+ subgroup established in 2022. Based on these
discussions, a report prepared by the TWG presents the TWGs views in applying the DCF+ evaluation methodology and provides
options and key considerations of potential enhancements to assist the Company in filing an enhanced DCF+ test.26 The TWG
recommends that the OEB give consideration to this report in its review of Enbridge Gas’s first non-pilot IRP application where the
DCF+ test will be filed for adjudication.
22 EB-2020-0091, OEB Decision and Order, page 36 23 Natural Gas Integrated Resource Planning (IRP) | Engage with Us (oeb.ca) 24 EB-2020-0091 Decision and Order, page 56-57. 25 A copy of the meeting materials for January 10, 2023, March 21, 2023, April 18, 2023, May 9, 2023, October 3, 2023, November 28, 2023 and December 12, 2023 can be found on the OEB Engagement website: Natural Gas Integrated Resource Planning (IRP) | Engage with Us (oeb.ca)
26 Use of the Discounted Cash Flow-Plus Test in Integrated Resource Planning (IRP): Report of the IRP Technical Working Group (May 30, 2023).
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One issue discussed with the TWG was the development of a DCF+ Supplemental Guide. The TWG, including Enbridge Gas,
agreed that a supporting guide should accompany the enhanced DCF+ test that Enbridge Gas files for approval with the OEB.
Enbridge Gas developed an initial draft guide to accompany the DCF+ test which describes the underlying methodological
considerations. This will promote consistent treatment and transparency of assumptions, assisting in the evaluation of facility
projects compared to supply-side and demand-side IRPAs in future IRP Plan applications. The DCF+ Supplemental Guide and
enhanced DCF+ test will together establish a basis for calculating and comparing the benefits and costs of both facility projects and
those IRPA solutions.
The initial draft Supplemental Guide was shared with TWG members on September 26, 2023. Enbridge Gas also prepared a
working Excel example of the DCF+ test which was shared with the TWG on November 24, 2023. Enbridge Gas continues to refine
the DCF+ test and Supplemental Guide based on feedback received from TWG members at the end of 2023 and will bring forward
an updated version in advance of the filing of the first non-pilot IRP Plan, informed by the details of the project. The enhanced DCF+
test and accompanying DCF+ Supplemental Guide will be filed for adjudication with its first non-pilot IRP Plan application.
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Section 10 – IRP Planning for 2024
This section provides a high-level summary of the work streams that Enbridge Gas expects to build upon and evolve further in 2024.
These work streams are continuations of the work completed in 2023 as Enbridge Gas continues to make strides regarding its pilot
and non-pilot IRP Plans, external stakeholder engagement initiatives, integration of IRP into the AIPM process, and the evolution
and filing of the Company’s DCF+ Handbook of Assumptions.
External Stakeholder Outreach
Enbridge Gas will continue with its external stakeholder efforts including ongoing engagement with municipalities through
conference attendance outlined below. Implementation of targeted engagement related to the IRP Pilot Projects will continue in
2024 as required.
Enbridge Gas will schedule regional or general stakeholder engagement sessions corresponding with updates to the Asset
Management plan. Feedback received from these stakeholder engagement sessions will be reviewed and considered in the load
forecasting process where possible, which will inform the 2024 AMP Addendum27.
Enbridge Gas has reached out to and engaged with Indigenous groups in both pilot areas, separate from the geotargeted public
engagement process, although Indigenous groups are welcome to attend all public engagement initiatives. Ongoing
communications will be shared via the Eastern region newsletter as outlined in Section 5.
Enhancements to the Regional Planning webpage and specific pilot and project pages will continue as projects develop to reflect
the updates to the IRP Pilot Projects noted in Section 4 and will include opportunities to share feedback with Enbridge Gas’s team
responsible for IRP-related stakeholder communication and community engagement.
Municipal
Enbridge Gas will continue its IRP outreach to municipalities across the province, involving targeted engagements of priority
municipalities with one-on-one discussions and regional webinars introducing changes in the AMP. IRP will continue to support the
Energy Transition team with engagement sessions focused on potential project areas.
Enbridge Gas will continue with outreach opportunities to reach wider audiences with the support and involvement of organizations
such as AMO and ROMA. In 2024, Enbridge Gas will continue to attend the AMO and ROMA conferences with IRP materials as it
had in 2023 and incrementally will ensure IRP is included in the Ontario Small Urban Municipalities, Ontario East Municipal, and the
Western Ontario Municipal Conferences where Enbridge Gas’s focus had not previously included IRP. These opportunities will be
leveraged to further develop the stakeholder mailing list to promote online engagement sessions and expand the stakeholder
network.
Electric Sector
Consultation with the IESO on best practices for Stakeholder Engagement and opportunities for planning coordination with IESO
and electricity LDCs will continue to be a priority for Enbridge Gas throughout 2024.
Continued IRP Evaluations
Upon finalization of the new AMP/10-year forecast, Enbridge Gas will continue to review and complete the technical and economic
evaluation processes for all remaining projects. As part of the continuous improvement of the IRP evaluation process, Enbridge Gas
plans to integrate binary screening into the Solution Planning & Value assessment stage of AIPM process with implementation and
training planned for 2024 to support the full integration of the IRP Screening into the AIPM process. For projects that pass both the
technical and economic evaluation, Enbridge Gas expects to develop and subsequently file a stand-alone non-Pilot IRP Plan
application and supporting evidence with the OEB for approval. Enbridge Gas plans to introduce an initial IRP Applicability
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 22 of 97
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Screening that would encompass the criteria in the Initial Technical Screening and minimum economic thresholds prior to the
technical and economic evaluation of applicable investments which will be discussed with the TWG.
An update on the projects reviewed has been provided as part of Enbridge Gas’s 2024 Rates Application proceeding (EB-2022-
0200). Please refer to the Asset Management Addendum - 2024 for the latest version of the information previously filed at EB-2022-
0200, Appendix B. An update will also be provided as part of the 2024-2025 Capital Plan anticipated to be filed in October 2024.
Additionally, Enbridge Gas will continue to work with Posterity Group on updating the IRP model through refreshing data inputs and
refining modelling approaches, assumptions, and methodologies to improve forecasting of peak hourly flow reduction potential and
costs. Enbridge Gas will bring forward key assumptions and elements of the model to the TWG and work to summarize the
information to allow for a more comprehensive understanding of the model to obtain technical input from the TWG.
DCF+ Test
Enbridge Gas continues to assess and incorporate feedback received in 2023 from the IRP TWG concerning the DCF+
enhancements and will file a submission on the DCF+ test as part of its first non-pilot IRP Plan application.28 Enbridge Gas
continues to consult with the IRP TWG on other issues and will bring forward issues related to DCF+ as needed. Notes and
presentations that continue during the IRP TWG meetings can be found on the OEB IRP TWG web page.29
Pilot Projects
Two IRP Pilot Projects were filed with the OEB in June 2023 under EB-2022-0335. As noted in Section 4 above, Enbridge Gas will
be filing updated evidence by June 28, 2024, reflecting the revised IRP Pilot Projects scope. The regulatory process to support
these two pilot projects will continue through 2024. Upon approval of the proposed IRP Pilot Project, Enbridge Gas will return to the
targeted communities with information sessions and additional details on the programming available. In advance of approval of the
proposed IRP Pilot Project, Enbridge Gas plans to proactively engage the larger commercial and industrial customers in the pilot
area in a targeted effort to identify potential participants and expedite the timelines and logistics associated with installing hourly
measurement to allow for the collection of baseline data prior to the rollout of the ETEE program and implementation of energy
efficiency measures.
Policy Proposals
In 2023 Enbridge Gas and the TWG held discussions on IRP-related policy proposals, with input informing considerations for
Enbridge Gas when it brings forward its first non-pilot IRP Plan application. Policy elements included attribution of DSM versus IRP,
the role of shareholder incentives and performance metrics, incrementality and the use of IRP Deferral Accounts, and consideration
of how risk associated with facility projects and IRPAs could be considered. Enbridge Gas will continue to consult with the IRP TWG
on these issues with the goal of contributing to the development of proposals prior to filing.
System Pruning
On December 21, 2023 the OEB issued its 2024 Rebasing Phase 1 Decision.30. The OEB asked with respect to system renewal
that Enbridge Gas consider system pruning, which for example, could include converting a subdivision from natural gas to electricity
for space and water heating, and further indicated that “the IRP process could offer alternatives through pilot projects for the OEB to
consider, including incentives to be paid to the customers to defray the cost of replacing their gas equipment, or investment by the
utility to cover the cost of the electric equipment to be recovered over time, with a return on that investment”31
System pruning involves the decommissioning of a portion of the natural gas system that is no longer required to serve the needs of
energy users. For this to occur, all customers served by that pipeline system must fully convert off natural gas and be willing to
28 EB-2020-0091, Decision and Order, page 56-57 29 Natural Gas Integrated Resource Planning (IRP) | Engage with Us (oeb.ca)
30 https://www.rds.oeb.ca/CMWebDrawer/Record/827754/File/document 31 EB-2022-0022 Decision and Order, Issued December 21, 2023, p. 52.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 23 of 97
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disconnect from the natural gas system. System pruning can be supported by an IRP solution, including supporting existing
customers in replacing their natural gas equipment with electric equipment.
In its submission for Phase 2 of its 2024 Rates Application, Enbridge Gas confirmed it is committed to working with the IRP TWG
and other relevant stakeholders to consult on system pruning processes and what role the Company could play in a system pruning
pilot.32 The system pruning work with the IRP TWG will occur at the appropriate time given the ongoing nature of Enbridge Gas’s
Phase 2 2024 Rates Application proceeding and will be informed by the government’s forthcoming policy statement on the role of
natural gas.
32 EB-2024-0111. Phase 2, Exhibit 1, Tab 17, Schedule 1, Page 17 – 27.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 24 of 97
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Appendix A: OEB IRP Directives and Progress Towards 2023 Priorities
The table below provides Enbridge Gas’s progress toward meeting the Directives as ordered by the OEB in the IRP Decision.
Directive Item Directive Status
Interruptible rates The OEB directs Enbridge Gas to study its
interruptible rates to determine how they might
be modified to increase customer adoption of
this alternative service.
Completed – filed with Enbridge Gas’s
2024 Rates Application (EB-2022-0200,
Exhibit 8, Tab 4, Schedule 7). As part of
the approved Settlement Proposal,
Enbridge Gas received approval to
implement negotiated interruptible rates as
part of an IRP plan (EB-2022-0200,
Decision on Settlement Proposal,
Schedule A, Page 50, Issue 28).
Documentation of
demand-side IRPAs
The OEB concludes that a document on the
best available information for demand-side
alternatives would promote more timely
development of IRP Plans and directs
Enbridge Gas to include a listing in its annual
IRP Report. The OEB agrees with Enbridge
Gas that supply-side alternatives require case-
by-case examination and therefore are not
required to be included in the listing.
Completed – list included in 2022 IRP
Annual Report. Updated list included in
Appendix B, Integrated Resource Plan
Alternatives.
Asset Management
Plan
The OEB directs that the AMP include
information about Enbridge Gas’ system
needs. This includes providing the status of
consideration of IRP Plans regarding meeting
system needs, the result of the binary
screening, and details on the evaluation.
Completed – filed with Enbridge Gas’s
2024 Rates Application (EB-2022-0200,
Exhibit 2, Tab 6, Schedule 2, Appendix B).
DCF+ test
enhancement
The OEB directs Enbridge Gas to study
improvements to the DCF+ test for IRP and, as
applicable, file an enhanced DCF+ test for
approval as part of the first non-pilot IRP Plan.
In progress – will be filed as part of
Enbridge Gas’s first non-pilot IRP Plan
application.
The report Use of the Discounted Cash
Flow-Plus Test in Integrated Resource
Planning (IRP): Report of the IRP
Technical Working Group presents the
TWG’s views on applying the DCF+
economic evaluation methodology.
IRP Website The OEB also directs the establishment of a
website by Enbridge Gas to facilitate the broad
sharing of information on IRP stakeholder
engagement efforts.
Phase 1 – Completed
Phase 2 – Completed
See Section 5 for description of IRP Web
content.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 25 of 97
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2023 IRP Annual Report
26
Technical Working
Group
Establishment of a TWG with the OEB
directing that membership should include
Enbridge Gas, OEB staff, independent experts,
and experienced non-utility stakeholders
Completed. The TWG members were
selected by OEB Staff as of December 6,
2021 with meetings commencing January
2022.
The TWG membership, Terms of
Reference and meeting folders with
materials and minutes is available at
Natural Gas Integrated Resource Planning
(IRP) | Engage with Us (oeb.ca)
IRP Deferral accounts The OEB directs Enbridge Gas to prepare a
Draft Accounting Order for the two IRP Costs
deferral accounts, consistent with the direction
of this decision.
Completed. On August 12, 2021, Enbridge
Gas filed its draft accounting orders for the
IRP Operating Costs Deferral Account and
IRP Capital Cost Deferral Account.
IRP Pilot projects The OEB expects that the IRP pilot projects
will be selected and deployed by the end of
2022 as proposed by Enbridge Gas. The
detailed consideration of IRP pilot projects
should commence shortly after the issuance of
the IRP Framework with input being sought
from the IRP Technical Working Group
described in chapter 10 (“Stakeholder
Outreach and Engagement Process”).
In progress – See Section 4
The table below provides Enbridge Gas’s progress toward meeting the 2023 priorities as defined in the 2022 IRP Annual Report
and 2022 IRP Technical Working Group report.
Item Priority Status
External Stakeholder
Outreach
External stakeholder outreach (including
broader discussions with municipalities and
municipal organizations, collaboration with
IESO on best practices, regional engagement
sessions, and geotargeted engagement in pilot
areas)
In progress – See Section 5
AMP update IRP binary screening, and technical and
economic evaluations of system needs in the
Asset Management Plan.
In progress – See Section 3
Cost Benefit Analysis DCF+ Test (submission as part of first non-pilot
IRP proceeding)
In progress – See Section 10
IRP Pilot Pilot projects (regulatory approval and
implementation)
In progress – See Section 4
Jurisdictional review Learnings from natural gas IRP in other
jurisdictions
Enbridge Gas shared with the TWG during
the meeting on December 12 ,2023 the
following recent jurisdictional scan on
natural gas IRP:
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 26 of 97
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2023 IRP Annual Report
27
Item Priority Status
Lawrence Berkley National Laboratory
/ Strategen: Non-Pipeline Alternative
Framework, Analysis and Experiences:
Non-Pipeline Alternatives to Natural Gas
Utility Infrastructure: An Examination of
Existing Regulatory Approaches
Non-Pipeline Alternatives: A Regulatory
Framework and a Case Study of Colorado
December 4, 2023 Presentation
Recorded webinar link
Shareholder
Incentives/
Performance metrics
Role of shareholder incentives and performance
metrics for IRP
In-progress – discussion with TWG in 2023
see Section 10
Incrementality and Use
of IRP Deferral
Accounts
Accounting treatment of IRP costs In-progress – discussion with TWG in 2023
see Section 10
Risk Treatment of risk In-progress – discussion with TWG in 2023
see Section 10
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 27 of 97
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2023 IRP Annual Report
28
Appendix B: Integrated Resource Planning Alternatives
As per the IRP Decision, the IRP Annual Report is to include “a summary of the best available information on demand-side IRPAs,
including the types of IRPAs, estimates of cost, peak demand savings, status in Ontario and learnings from pilot projects and other
jurisdictions”. Additionally, a summary of the best available information on supply-side IRPAs has been included below.
Demand Side IRP Alternatives
Enhanced Targeted Energy Efficiency (“ETEE”)
IRPA Overview
Enhanced targeted energy efficiency (“ETEE”) programs focus on achieving necessary reductions in a specific geographical
area to reduce peak period system demands. ETEE programs could include enhancing existing broad-based Demand Side
Management (“DSM”) offerings through additional incentives and targeted marketing, or introducing new geo-targeted
programs not offered through broad-based DSM. The mix of offerings and measures utilized in an ETEE program is dependent
on the scope of the facility investment project under consideration, customer characteristics in the specific project services
area, past DSM participation, etc.
Broad-based DSM programs have been offered to natural gas customers across Ontario since 1993. On November 15, 2022,
the OEB issued its Decision for the Company’s 2023-2025 DSM Plan (EB-2021-0002) to guide ongoing broad-based DSM
programming. As defined by the OEB in their DSM Letter, the objective of broad-based DSM is “assisting customers in making
their homes and businesses more efficient in order to help better manage their energy bills”.
As ETEE programs focus on peak hour reductions, many ETEE measures would focus on enhancing existing broad-based
DSM measures such as space heating equipment, water heating equipment, and building envelope upgrades.
Enbridge Gas will be undertaking IRP Pilots, pending OEB approval, as part of the IRP Pilot Projects proceeding (EB-2022-
0335) to develop an understanding of how to design, deploy and evaluate ETEE programs and how ETEE programs impact
peak hour demand within a geo-targeted area. Additional measures being considered are newer advanced technologies,
including thermal energy storage, simultaneous hybrid heating, and gas heat pumps as well as electrification measures
including ground source heat pumps and cold climate air source heat pumps. The learnings from these IRP Pilots, as well as
any non-pilot IRP Plans, will be incorporated into future iterations of the IRP Annual Report’s Appendix B, “Demand Side
Alternatives”.
IRPA Peak Impacts
Forecast peak impacts will be estimated on a case-by-case basis depending on the ETEE program.
Enbridge Gas worked with Posterity Group to build an end-use model of its service territory with the 2019 Achievable Potential
Study (“APS”) being the starting point for the IRP model. First, a mirror model of the APS was created and then several
adjustments were made to better reflect Enbridge Gas’s knowledge and experience of the Ontario DSM market, Enbridge
Gas’s current Technical Resource Manual (TRM) assumptions, and known changes to applicable standards.33 Posterity Group
then worked with Enbridge Gas to develop peak factors which were added to the IRP model so that enhanced targeted energy
efficiency peak hour impact estimates could be developed for each region, sector, segment, and end use.34 Posterity Group’s
33 Posterity Group report detailing the development and assumptions of the underlying mirror model (EB-2021-002, Exhibit E, Tab 4, Schedule 7, Attachment 1 – “Demand Side Management Planning Support Final Report Documenting Data Inputs, Assumptions and Method (April 2021)" - Link 34 Posterity Group memo on peak modelling methodology and hours-use peak factor assumptions (filed as part of EB-2022-0157 (PREP) – Exhibit I.ED.7, Attachment 4) - Link. Posterity Group memo on calculation of peak reduction on an efficiency measure (July 2022) - Link
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 28 of 97
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29
IRP model is run through Posterity’s Navigator software, where the details in how the Navigator software works and how the
model parameters interact with each other are available and documented.35
Posterity Group and Enbridge Gas are working to evolve this model by refining assumptions and assessment methodologies to
refine and improve forecasting of peak hourly flow reduction potential. It is expected that the ETEE programs as part of the IRP
Pilots will provide greater insight on the peak impacts of such programs.
IRPA Cost Details
Costs will be determined on a case-by-case basis depending on the ETEE program.
The Posterity model described above also includes cost assumptions for ETEE programs, based largely on the APS, with
adjustments made in an attempt to better reflect Enbridge Gas’ knowledge and experience of the Ontario DSM market.36
Posterity Group and Enbridge Gas plan to continue to evolve this model by refining assumptions and assessment
methodologies so it can be used to assess project specific costs for an ETEE program.
It is expected that the ETEE programs as part of the IRP Pilots will provide greater insight on the costs of such programs.
IRPA Deployment Strategy
The selection of energy efficiency measures for an ETEE program and the deployment strategy would be dependent upon the
scope of the facility investment project under consideration, customer characteristics in the specific project service area, past
DSM participation, etc.
The IRP Pilots will provide insights that could guide the deployment strategy of future IRP ETEE programs. The pilots could
also provide insights on the deployment strategy into the richness of customer ETEE incentive levels and the intensity of the
ETEE program delivery approaches for various customer groups to drive the participation uptake levels necessary to meet
peak demand reduction requirements.
IRPA Solution Timing
Timing on an ETEE IRPA solution is dependent upon the scope of the facility system need under consideration, the type of
ETEE program(s) being considered, and the customer characteristics in the specific project service area. A high-level estimate
of a 3-to-5-year minimum lead time would be required to support program implementation and deployment, and subsequent
performance measurement to evaluate the impact to the system peak hour. ETEE can be deployed with supply-side IRPA(s) to
defer the system need and ensure that Enbridge Gas can reliably meet peak hour system demand requirements while
demand-side ETEE IRPA(s) are implemented.
IRPA Implementation Risks/Challenges
There are several operational risks related to ETEE:
- Principle of universality (offering different DSM programing and incentives to different customers).
- Undersubscription of ETEE programming to meet peak demand requirements to delay or avoid the facility system
need.
- Uncertainty on the reliability of peak reduction capabilities of ETEE measures to be delivered in a cost-effective
manner for facility planning.
- Coordination of timing between fully effective ETEE IRPAs and meeting the system needs.
35 Posterity Group, Enbridge’s Navigator End-Use Model Presentation: Posterity (Enbridge's Navigator End-Use Model) and “Navigator Energy and Emissions Simulation Suite – Functional Specification Document” (filed in EB-2022-0200 – Exhibit I.1.10-SEC-29, Attachment 1) - Link 36 Posterity Group report detailing changes to reference case assumptions on DSM measures (EB-2021-002, Exhibit E, Tab 4, Schedule 7, Attachment 1, Appendix A) – “Demand Side Management Planning Support Final Report Documenting Data Inputs, Assumptions and Method (April 2021)" - Link
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 29 of 97
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30
- Current lack of experience in implementing ETEE programming; DSM expertise in delivery programming has been
broad-based.
- Variances in energy planning and the lack of coordinated energy planning between gas utilities, electric distributors
and the IESO. Risk of insufficient electrical capacity to absorb electric measures as part of an ETEE program.
Learnings from Pilot Projects/Other Jurisdictions
Enbridge Gas has indicated 2023 learnings from natural gas IRP in other jurisdictions in Appendix A.
In 2022, Enbridge Gas engaged Guidehouse to undertake a jurisdictional review of ETEE and DR natural gas pilots
implemented for general service customers, where the pilots’ objectives were to defer or avoid infrastructure.37 Guidehouse
focused on three jurisdictions, summarizing the pilot objectives, marketing activities, costs, findings, and challenges faced.
Additionally, Guidehouse noted challenges in data availability in completing the jurisdictional review.
Enbridge Gas filed a Geo-Target Demand Side Management Case Study in EB-2020-0091 at Exhibit C, Appendix A. The
objectives of the case study were:
1. Assessment of the impacts of geo-targeted DSM programs on reducing peak hour demand.
2. Assessment of the costs of geo-targeted DSM program implementation.
The results from this case study only illustrate the impacts geo-targeted DSM had on the town of Ingleside and although
informative and directional, the results cannot be generally applied due to the specific nature of customer composition.
The OEB had determined that it is not appropriate to provide funding to Enbridge Gas for electricity IRPAs as part of the first-
generation IRP Framework; however, the Company is testing electric heat pumps as part of the IRP Pilot application to
evaluate these measures on a limited basis and as a component of the broader DSM programming. To better understand how
non-pipeline electric alternatives could be offered more broadly in the future, Enbridge Gas has undertaken some jurisdictional
research in-house including attending industry webinars.
High-level learnings to date include that the Colorado Public Utilities Commission includes beneficial electrification as a non-
pipeline alternative to offset gas infrastructure investments in the long-term. The New York Public Commission encourages gas
utilities in New York to offer building electrification as a non-pipeline alternative as part of a program to remove leaking or leak-
prone gas infrastructure. In California, the California Public Utilities Commission considers electrification as a non-pipeline
alternative to meet energy needs in utilities gas-planning activities, and one utility is offering a small electrification program to
facilitate the retirement of gas assets.38 Additionally, the California Energy Commission is funding two building electrification
and gas infrastructure decommissioning pilots.39
Many of the utilities reviewed in other jurisdictions are dual-fuel utilities with ability to coordinate internally, whereas Enbridge
Gas would require coordinated planning with the IESO and LDCs to consider similar electrification plans. Enbridge Gas intends
to continue its jurisdictional research into non-pipeline electric alternatives as part of its IRP demand-side alternatives, and of
jurisdictions seeking to electrify customers as a means to decommission natural gas distribution pipelines.
Demand Response (“DR”)
37 IRP ETEE-DR Pilot Review April 8, 2022 Guidehouse (IRP ETEE-DR Pilot Review)38 Strategen, Non-Pipeline Alternatives to Natural Gas Utility Infrastructure: An Examination of Existing Regulatory Approaches, November 2023. 38 Strategen, Non-Pipeline Alternatives to Natural Gas Utility Infrastructure: An Examination of Existing Regulatory Approaches, November 2023.
39 California Energy Commission, Gas Research and Development Program Proposed Budget Plan for Fiscal Year 2023-2024, May 2023. CEC-500-2023-020.pdf (ca.gov)
IRPA Overview
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 30 of 97
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40 https://www.calmac.org/publications/SoCalGas_2019_DR_Evaluation_Report_-_PUBLIC_FINAL.pdf 41 Adjustment for Ontario climate/buildings provided on p.2 - Link
Natural gas demand response aims to reduce natural gas customers’ demand during peak periods. For residential and
commercial customers, this can commonly be seen in the form of gas demand reductions during DR program events via
thermostat control or water heater temperature settings. For contract customers, this can be done through leveraging
interruptible rates.
Demand response would include:
1. Negotiable interruptible rate - as detailed in Section 9, the use of interruptible rates was reviewed as part of the IRP
Framework Decision, and Enbridge Gas filed an Interruptible Rate Study that evaluated the use of demand response
in the context of future IRP Plan Application where applicable.
2. Utilization of another alternative (i.e., onsite CNG) when a peak hour/day event is called.
3. Incentives to shift peak hourly demands to off-peak periods.
Enbridge Gas will be undertaking an IRP Pilot, pending OEB approval as part of the IRP Pilot Project proceeding (EB-2022-
0335) to develop an understanding of how to design, deploy and evaluate residential DR programs and how residential DR
programs impacts peak hour demand within a geo-targeted area. The learnings from the IRP Pilot, as well as any non-pilot IRP
Plans, will be incorporated into future iterations of the IRP Annual Report’s Appendix B, “Demand Side Alternatives”.
IRPA Peak Impacts
Peak impacts will be determined on a case-by-case basis depending on the DR service (e.g., program, rate design etc.).
As a starting point for a residential space heating smart thermostat program, an estimated impact of 18.5% peak gas (m3/hr)
reduction was developed based on the evaluation of SoCal’s residential smart thermostat DR program40 and adjusted for
Ontario climate/buildings.41
It is expected that the residential DR program as part of the IRP Pilot Projects will provide greater insight on the peak impacts
of such a program.
IRPA Cost Details
DR IRPA costs will be determined on a case-by-case basis depending on the DR service (e.g., program, rate design etc.).
It is expected that the residential DR program as part of the IRP Pilot Projects will provide greater insight on the actual costs to
deploy such a program.
IRPA Deployment Strategy
The deployment strategy will be determined on a case-by-case basis depending on the customer mix and characteristics in the
project area.
The IRP Pilot residential DR program will provide insights that could guide the deployment strategy for future programming.
For contract rate customers, as part of the IRP evaluation process, Enbridge Gas will engage with all contract customers in the
project area to assess whether those customers could reduce their peak demands, convert their firm demand service to
interruptible service or leverage another fuel source.
IRPA Solution Timing
DR IRPAs are dependent upon the scope of the facility system need under consideration, the type of DR program being
considered, and the customer characteristics in the specific project service area.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 31 of 97
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42 IRP ETEE-DR Pilot Review April 8, 2022 Guidehouse (IRP ETEE-DR Pilot Review)
The IRP Pilot residential DR program would provide insight on the time required to design a DR program and to deliver a DR
program to reach participation levels required of the specific facility IRPA.
Engagement of contract rate customers will occur as part of the detailed technical assessment.
IRPA Implementation Risks/Challenges
There are several operational risks related to a residential DR program:
Principle of universality (offering DR programing/incentives to different geographically specific customers)
Undersubscription and lack of persistent participation of DR programming to meet peak demand requirements of the delay
or avoidance of facility system need
Uncertainty on the reliability of cost-effective DR performance for facility planning
Coordination of timing between fully effective DR IRPAs and meeting the system needs
Current lack of experience in implementing DR programming; Enbridge Gas has not previously implemented a gas-DR
program for general service customers.
Learnings from Pilot Projects/Other Jurisdictions
In 2022, Enbridge Gas engaged Guidehouse to undertake a jurisdictional review of ETEE and DR gas pilots implemented for
general service customers, where the pilots’ objectives were to defer or avoid infrastructure 42. Guidehouse focused on three
jurisdictions, summarizing the pilot objectives, marketing activities, costs, findings, and challenges faced. Additionally,
Guidehouse noted challenges in data availability in completing the jurisdictional review.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 32 of 97
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Supply Side IRP Alternatives
Compressed Natural Gas (“CNG”)
IRPA Overview
CNG is a mobile solution that can be used in place of traditional pipeline reinforcement to meet customer demands at peak
hours on peak days. Natural gas is compressed into large tube trailers and moved by trucks from the compression station “hub”
to a mobile decompression station “spoke” where the gas is delivered into the pipeline.
This is an active control best utilized in long, single feed pipe networks with cold weather peaking loads. hub stations are
situated in relative proximity to spoke stations (within 200 kms) to minimize driving distance.
IRPA Peak Impacts
CNG targets peak hours on peak demand days, where the injection of gas back into the system at the spoke station would have
an equivalent 1 for 1 offset of gas otherwise required to flow through the traditional pipeline bottleneck. Injecting near the low-
pressure point on the system would magnify the benefit beyond 1 for 1 on a hydraulic basis. Although the trailered gas will need
to be withdrawn from the system at the hub station, this can be done at off-peak times and locations and where capacity is
available.
IRPA Cost Details
From a capital cost perspective:
• Tube trailers typically have a capacity of 10,000 m3 of natural gas (at standard conditions) and cost approximately
$700,000 per trailer with a 15-year useful life.
• Hub and spoke stations costs can vary based on capacity requirements, but typically cost approximately $300,000 and
$3M per station, respectively, with a 20+ year useful life.
Capital costs may be impacted by the procurement strategy of utilizing a third-party vendor or procurement of the asset by
Enbridge Gas.
From an operational cost perspective, the equipment requires regular maintenance and supervised operation. Drivers are also
required to drive the trailers between the hub and spoke stations with highway tractors.
IRPA Deployment Strategy & Timing
The equipment is mobile and can be deployed in various locations throughout the province. CNG would be most ideal in areas
where the gas demands are large enough to achieve economies of scale but small enough to be practical. For instance, the
transmission pipeline scale is too large as it may require hundreds of trailers, but a few households would be too small as a
single trailer will be underutilized. Additional consideration based on location would impact the suitability of CNG as a solution,
such as urban versus rural and the number of trucks required.
Depending on the system need and location, CNG can be a suitable bridging solution for ETEE implementation or for the
deferral of baseline facility projects as system needs may evolve, inclusive of the energy transition landscape in Ontario. CNG
can be deployed in a relatively short amount of time, and can be scalable by the addition of mobile compressor stations and
trailers.
IRPA Implementation Risks/Challenges
The biggest risk associated with this solution is a potential disruption in the supply of trailers to the spoke station, for instance
road closure due to weather or an accident while in transit. To mitigate this risk, extra trailers can be made available on-site at
the spoke station and the associated additional costs would need to be considered when assessing the viability of this IRPA.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 33 of 97
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Market-Based Supply
IRPA Overview
Market-based supply-side IRP alternatives include incremental natural gas deliveries or pressure increases at specific
interconnects or points between Enbridge Gas’s system and other pipelines such as the TC Energy Mainline and US based
pipelines such as Panhandle Eastern Pipeline Company and Vector. Contracting for market-based supply-side alternatives into
Enbridge Gas’s franchise area, where applicable and available, can reduce, defer or mitigate traditional infrastructure by
meeting incremental natural gas demands in a defined area with incremental deliveries or pressure.
IRPA Peak Impacts
Incremental deliveries or increased pressure must be delivered in the project's area to impact peak hour demands. Therefore,
market-based supply side alternative options are limited to interconnects with TC Energy along the mainline and Enbridge Gas’s
system or with interconnects with other pipelines that connect to Enbridge Gas’s system such as Parkway, Ojibway and Dawn.
IRPA Cost Details
Market-based supply-side alternative costs are based on market dynamics at the time of contracting. Enbridge Gas cannot
forecast the cost of market-based supply-side options on a long-term basis.
IRPA Deployment Strategy and Timing
Enbridge Gas can contract and deploy market-based supply-side alternatives if the deliveries from a third party or pipeline are
available. However, for US pipelines, the Federal Energy Regulatory Commission rules dictate that US pipelines cannot sell
capacity more than “90 days from the contract start date”. Given that many of Enbridge Gas’s interconnects are with US
pipelines it may be difficult to utilize the market-based supply-side services for an IRP alternative.
IRPA Implementation Risks/Challenges
There are two primary operational risks with market-based supply-side alternatives: lack of renewal rights and failure to deliver.
Most market-based supply-side alternatives are short-term (1-2 years) and lack renewal rights making it difficult to rely on long-
term to reduce or mitigate a project need. In many instances, a market-based supply-side alternative will be used to defer a
project in the short-term and then the need and IRP alternatives will need to be reassessed.
While Enbridge Gas may have contracted for a market-based supply side alternative, if the capacity underpinning the service is
not firm, then natural gas market dynamics may cause the supplier to fail on its delivery obligations. For example, without firm
capacity underpinning the market-based service, during peak weather events upstream pipeline systems may become
constrained and non-firm services can be curtailed. If the service provider is relying on non-firm services, it may be unable to
supply natural gas to Enbridge Gas. While contract penalties and other contract language may limit most events like the
example above from happening, it remains a legitimate and material risk. If the contracted service was not delivered as planned,
Enbridge Gas could have insufficient gas supply deliveries to meet its market demands; potentially resulting in a system outage
during the coldest periods of the year. While Enbridge Gas would collect financial penalties, if applicable, after the event
occurred, Enbridge Gas would still need to deal with the physical and customer impacts that resulted due to the failed delivery of
the incremental gas on that day.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 34 of 97
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Appendix C: Summary of IRP Evaluations
Refer to the Asset Management Plan Addendum – 2024 in EB-2020-0091 for the most current Appendix B and the
results of Enbridge Gas’s IRP Assessment Process for system needs, including reporting on those system needs
where a negative binary screening, technical or economic evaluation resulted in no further assessment of IRPAs.
In lieu of providing the same Appendix B as previously filed, the status of a subset of investments prioritized for IRP
assessment that passed technical evaluation are summarized in Appendix C. The impacts of the SRP update and ET
adjustments on these 26 projects and the 2 corresponding Pilot facility projects were prioritized and included as part
of Appendix C.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 35 of 97
Page 537
Region Operating Area
(EGI) Asset Class Binary Screening
(Pass / Fail)Investment Code Investment Name In Service
Date
2023-2032 Forecast
(Includes overhead
allocation)
Technical Evaluation
Completion Status Technical Evaluation Results Technical Evaluation Comments Status Updated In-
Service Date
Draft 2025-2034
Forecast (Includes
overhead allocation)
Eastern 60 - Ottawa Growth Pass 7743 SRP2024_(60)Ottawa_L'Original_ROW_Reinforcement_NPS8_3300m_XHP 2025 6,691,362$ Completed Pass CNG, ETEE - CNG potentially could defer project scope, ETEE potentially could
eliminate (with CNG as bridging solution), reduce or defer project scope.
IRP Assessment Ongoing - Project in AMP, LTC Required 2026
GTA West 20 - Mississauga Growth Pass 30500 SRP2024_(20)Missisauga_Shelburne_Blind
Line_Reinforcement_NPS8_15700m_XHP_&_3730322_Upgrade
2024 7,148,925$ Completed Pass CNG, ETEE - CNG potentially could reduce or defer project scope, ETEE potentially
could reduce or defer project scope.
IRP Assessment Ongoing - Project in AMP, LTC Required 2026 $
6,647,130
Eastern Div_22 - Kingston Growth Pass 30507 SRP_LUG East_Kingston_28401002STN &
Reinforcement_NPS12_1000m_1210kPa
2024 -$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Rejected - No longer in 10 year AMP
Eastern Div_22 - Kingston Growth Pass 30522 SRP_LUG East_Winchester_Main St_Reinforcement_NPS4_550m_1724kPa 2028 613,098$ Completed Pass CNG, ETEE - CNG potentially could reduce or defer project scope, ETEE potentially
could eliminate, reduce or defer project scope.
Rejected - No longer in 10 year AMP
Northern Div_43 - Sudbury &
S.S. Marie
Growth Pass 30523 SRP_North_Parry Sound_Seguin Trail_Reinforcement_IRP Pilot [743722]2027 270,022$ Pass CNG, ETEE - CNG potentially
could reduce or defer project
scope, ETEE potentially could
reduce project scope
N/A - Pilot Project Pilot Project facility no longer in 10 year AMP
Southeast Div_07 - Waterloo Growth Pass 30528 SRP_Southeast_Baden_Peel St_Reinforcement_NPS6_400m_420kPa 2028 638,526$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Rejected - No longer in 10 year AMP
Southeast Div_07 - Waterloo Growth Pass 30529 SRP_Southeast_Brantford_Maple Grove
Rd_Reinforcement_NPS6_830m_420kPa
2027 1,271,016$ Completed Pass CNG, ETEE - CNG potentially could defer the project scope, ETEE potentially could
reduce or defer the project scope.
Rejected - No longer in 10 year AMP
Southeast Div_07 - Waterloo Growth Pass 30532 SRP_Southeast_Breslau_Sawmill Rd_Reinforcement_NPS4_500m_3450kPa 2027 765,673$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Rejected - No longer in 10 year AMP
Southeast Div_07 - Waterloo Growth Pass 30536 SRP_Southeast_Cambridge_Guelph Ave_Reinforcement_NPS6_1000m_420kPa 2026 1,497,708$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Rejected - No longer in 10 year AMP
Southeast Div_07 - Waterloo Growth Pass 30542 SRP2024_(07)Brantford/Waterloo_Owen Sound_County Rd
40_Reinforcement_NPS12_11800m_4670kPa
2025 5,101,857$ Completed Pass CNG, ETEE - CNG potentially could reduce or defer project scope, ETEE potentially
could reduce or defer project scope.
IRP Assessment Ongoing - Project in AMP, LTC Required 2031 $ 36,778,983
Southeast Div_07 - Waterloo Growth Pass 30547 SRP_Southeast_Southampton_30N-501STN_Rebuild 2030 1,291,775$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Rejected - No longer in 10 year AMP
Southeast Div_07 - Waterloo Growth Pass 30548 SRP_Southeast_Southampton_South St_Reinforcement_NPS6_600m_550kPa 2028 957,790$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Rejected - No longer in 10 year AMP
Southwest Div_04 - London Growth Pass 30555 SRP_Southwest_Kettle Point_Ravenswood
Line_Reinforcement_NPS4_2000m_3450kPa
2027 2,266,318$ Completed Pass CNG, ETEE - CNG potentially could reduce or defer project scope, ETEE potentially
could eliminate, reduce or defer project scope.
Rejected - No longer in 10 year AMP
Southwest Div_04 - London Growth Pass 30558 SRP_Southwest_London_Byron Baseline_Reinforcement_NPS8_700m_420kPa¹2023 861,500$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Project Completed and in-service¹
Southwest Div_04 - London Growth Pass 30560 SRP_Southwest_Sarnia_New STN & Reinforcement_NPS6_1600m_420kPa [IRP
Pilot for 743910]
2023 360,030$ Pass CNG, ETEE - Potentially could
defer project scope.
N/A - Pilot Project Pilot Project facility no longer in 10 year AMP
Southwest Div_04 - London Growth Pass 30563 SRP_Southwest_Bluewater_New STN & Reinforcement_NPS4_7200m_3450kPa 2025 8,656,067$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Rejected - No longer in 10 year AMP
Southeast Div_07 - Waterloo Growth Pass 49079 SRP2024_(07)Brantford/Waterloo_Guelph_Victoria Rd
S_Reinforcement_NPS2_450m_420kPa
2026 1,228,795$ Completed Pass CNG, ETEE - CNG potentially could reduce or defer project scope, ETEE potentially
could eliminate, reduce or defer project scope.
Project in AMP¹ and falls in the Low Cost, Low Value
Category²
2026 $ 261,532
Southeast Div_07 - Waterloo Growth Pass 49794 SRP2024_(07)Brantford/Waterloo_Listowel_CNG 2024 827,794$ Completed Pass CNG, ETEE - CNG potentially could reduce or defer project scope, ETEE potentially
could eliminate, reduce or defer project scope.
IRP Assessment Ongoing - Project in AMP as CNG
Placeholder, LTC Required
2025 $ 1,024,299
Eastern Div_22 - Kingston Growth Pass 100703 SRP_LUG East_Kingston_Creekford Rd_Reinforcement_NPS8_6200m_6895kPa 2027 2,163,249$ Completed Pass CNG, ETEE - Potentially could reduce or defer project scope.Rejected - No longer in 10 year AMP
GTA East 40 - Whitby Distribution
Pipe
Pass 735948 AR40: VSM Replacement - Wilson Rd S Oshawa Ph 1 Bloor to Olive 2025 2,072,401$ Completed Pass ETEE - Potentially could reduce project scope.IRP Assessment Ongoing - Project in AMP, LTC Required 2026 $ 1,819,464
GTA East 40 - Whitby Distribution
Pipe
Pass 735949 AR40: VSM Replacement - Wilson Rd S Oshawa Ph 2 Olive to King 2025 2,931,376$ Completed Pass ETEE - Potentially could reduce project scope.Rejected - No longer in 10 year AMP
Southwest Div_04 - London Distribution
Pipe
Pass 736302 Wardsville Line - Southwest - London - 1797 2031 13,090,345$ Completed Pass ETEE - Potentially could reduce project scope.Deferred out of 10 year AMP
GTA East 40 - Whitby Growth Pass 736524 NW 4793 Carnwith Dr. Brooklin Reinforcement SRP 2024 369,854$ Completed Pass CNG, ETEE - Potentially could defer project scope.Project in AMP, no longer driven by SRP, ongoing scope
evaluation pending confirmation of customer needs
2025 $ 278,745
Eastern 60 - Ottawa Growth Pass 736680 SRP2024_(60)Ottawa_Ottawa_Laurier_Reinforcement_NPS2_15m_379kPa 2024 291,327$ Completed Pass CNG, ETEE - CNG potentially could defer project scope, ETEE potentially could
reduce or defer project scope.
Project in AMP¹ and falls in the Low Cost, Low Value
Category²
2025 $ 269,849
Eastern 60 - Ottawa Growth Pass 736682 NW 6544 Bank St. Reinforcement SRP 2024 -$ Completed Pass CNG, ETEE - CNG potentially could defer project scope, ETEE potentially could
eliminate or defer project scope.
Rejected - No longer in 10 year AMP
Eastern 60 - Ottawa Growth Pass 736760 NW 6652 Bunker Rd. Reinforcement SRP 2028 -$ Completed Pass CNG, ETEE - CNG potentially could defer project scope, ETEE potentially could
eliminate, reduce or defer project scope.
Rejected - No longer in 10 year AMP
Eastern 60 - Ottawa Growth Pass 736761 NW 6579 Kemptville Reinforcement SRP 2026 -$ Completed Pass CNG, ETEE - CNG potentially could defer project scope, ETEE potentially could
reduce project scope with CNG as a bridging solution.
Rejected - No longer in 10 year AMP
Eastern 60 - Ottawa Growth Pass 736762 NW 6463 Embrun Reinforcement SRP¹2023 850,893$ Completed Pass CNG, ETEE - CNG potentially could defer project scope, ETEE potentially could
reduce project scope with CNG as a bridging solution.
Project Completed and in-service¹
(1) Investment 736762 and 30558 went in-service at the end of 2023 and both had project spend beginning in 2022. IRP assessments were completed in Q1 2023 in adherence to the IRP evaluation process. Due to the progression of the project planning phase and relatively low dollar value of the investments, proceeding with the execution phase of the investments was determined to be prudent.
(2) Low Cost, Low Value Category as filed in the Appendix B with the Asset Management Plan Addendum – 2024 under EB-2020-0091
Output from Appendix B Addendum Post 2024 SRP with ET Adjustment Factors
$
36,447,118
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 36 of 97
Page 538
37
Appendix D: IRP Screening Results for LTC Projects
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 37 of 97
Page 539
38
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
EB-2022-0203 Ridge Landfill
RNG
Fail Enbridge Gas applied the IRP Binary Screening Criteria and
determined that this Project meets the definition of a
Customer-Specific Build, as defined in the IRP Framework:
Customer-Specific Builds – If an identified system need has
been underpinned by a specific customer’s (or group of
customers’) clear request for a facility project and either the
choice to pay a Contribution in Aid of Construction or to
contract for long-term firm services delivered by such
facilities, then an IRP evaluation is not required. The Project
was driven solely by a specific customer’s (Waste
Connections) request for facilities to connect to Enbridge
Gas’s existing natural gas distribution system. Waste
Connections has executed a long-term contract including a
CIAC to fully fund the cost of the Project.
OEB Decision dated April 6, 2023: the
proposed Project falls under the customer-
specific build category in the OEB’s IRP
framework, which obviates the need for an
IRP evaluation.
EB-2022-0155 Crowland well
upgrade
replacement
project
Enbridge Gas stated that it is not aware of any comparable
alternative facility or non-facility solution that would enable
gathering information on the rock properties of these specific
geological formations.
OEB Report of the Board September 13,
2022: found that there is a need for the
Project. The OEB notes that any future
conversion of EC 1 from a test well to an
observation or injection/withdrawal well would
be subject to Enbridge Gas receiving
approvals from the MNRF.
EB-2022-0086 Dawn to Corunna
Replacement
Project
Fail The Company applied the OEB-approved Binary Screening
Criteria to the Project and determined that it is not possible to
implement and resolve the identified system constraint within
the timeframe required. As stated in the OEB’s IRP
Framework for Enbridge Gas: ii. Timing - If an identified
system constraint/need must be met in under three years, an
IRP Plan could not likely be implemented, and its ability to
OEB Decision dated November 3, 2022: found
that the assessment of alternatives was
sufficient for the purpose of selecting the
Project as the preferred option.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 38 of 97
Page 540
39
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
resolve the identified system constraint could not be verified
in time. Therefore, an IRP evaluation is not required.
Exceptions to this criterion could include consideration of
supply-side IRPAs and bridging or market-based alternatives
where such IRPAs can address a more imminent need.
Although an IRP assessment was not required, Enbridge Gas
did undertake an IRP review. This found that the cost of an
ETEE program that could deliver 90 TJ/d of demand
reduction in the most favorable market downstream (EGD
rate zone – CDA) of the Project is estimated to be
approximately $980 million. Further, this alternative would
require additional expenditures of a similar magnitude every
10-15 years to maintain this reduction over the depreciable
life of the proposed Project, which is currently anticipated to
be approximately 40 years
The OEB found that an Integrated Resource
Planning assessment is not required in this
case under the current Integrated Resource
Planning Framework.
EB-2022-0003 NPS 20
Waterfront
Relocation Project
Fail Enbridge Gas applied the Binary Screening Criteria and
determined that the need underpinning the Project does not
warrant further IRP consideration, as the Project is driven by
a need that must be met within 3 years: Timing - If an
identified system constraint/need must be met in under three
years, an IRP Plan could not likely be implemented and its
ability to resolve the identified system constraint could not be
verified in time. Therefore, an IRP evaluation is not required.
Exceptions to this criterion could include consideration of
supply-side IRPAs and bridging or market-based alternatives
where such IRPAs can address a more imminent need.
OEB Decision dated July 7, 2022: found that
an IRP assessment is not required in this case
given that the proposed Project is a like-for-
like with no growth component and has a tight
timeline.
EB-2022-0088 Haldimand
Shores
Fail Enbridge Gas applied the Binary Screening Criteria and
determined this Project meets the definition of a community
OEB Decision dated August 18,2022:
Enbridge Gas Inc. is granted leave, pursuant
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 39 of 97
Page 541
40
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
Community
Expansion Project
expansion project defined in the IRP Framework as the
Project has been approved by the Government of Ontario as
part of the Phase 2 NGEP to provide access to natural gas
distribution services in the community of Haldimand Shores.
Consequently, the need underpinning the Project does not
warrant further IRP consideration. iv. Community Expansion
& Economic Development – If a facility project has been
driven by government legislation or policy with related funding
explicitly aimed at delivering natural gas into communities,
then an IRP evaluation is not required.
to section 90(1) of the OEB Act, to construct
the Project in the Township of
Alnwnick/Haldimand as described in the
Application. The OEB finds that the Project is
the best alternative to meet the need.
In EB-2020-0091 the OEB approved an
integrated resource planning process for
Enbridge Gas that required an evaluation and
comparison of options to meet energy supply
needs. To meet the Ontario Government’s
Natural Gas Expansion Program (NGEP)
objective of bringing service to unserved
communities the OEB provided that the
consideration of such options or alternatives
was not required for NGEP approved projects
that have been designated in Ontario
Regulation 24/19. The OEB’s decision in this
proceeding is in accordance with its approved
integrated resource planning process
EB-2022-0247 Metrolinx
Scarborough
Extension –
Kennedy Station
Fail Fail Enbridge Gas applied the Binary Screening Criteria and
determined that the need underpinning the Project does not
warrant further IRP consideration based on the timing criteria,
as the need must be met in under three years (the proposed
project has in-service dates of December 2023 for Phase 1,
and July 2025 for Phase 2). In addition, the Project is driven
by a customer-specific build where Metrolinx will reimburse
Enbridge Gas through a Contribution in Aid of Construction
(“CIAC”) for the actual Project costs.
OEB Decision dated May 9, 2023: Enbridge
Gas Inc. is granted leave, pursuant to section
90(1) of the OEB Act, to construct the Project
in the City of Toronto as described in its
application.
In the OEB’s Decision the OEB finds that the
Project is the best alternative to meet the
stated need. The Project is excluded from IRP
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 40 of 97
Page 542
41
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
considerations for the following reasons: the
Project addresses a system need that must be
met in under three years; Metrolinx will pay all
project costs. The project is within the intent of
the findings made by the OEB in the IRP
Framework decision regarding customer
specific builds where the customer fully pays
for incremental infrastructure cost.
EB-2022-0248 Mohawks on the
Bay of Quinte
First Nation
Community
Expansion
Fail Enbridge Gas applied the Binary Screening Criteria and
determined that the proposed Project meets the definition of
a community expansion project under the IRP Framework, as
the Project has been approved by the Government of Ontario
as part of the Phase 2 NGEP to provide access to natural gas
distribution services in MBQFN and the Township.
Consequently, the need underpinning the Project does not
warrant further IRP consideration.
OEB Decision dated September 21, 2023:
Enbridge Gas Inc. is granted leave, pursuant
to section 90(1) of the OEB Act, to construct
the Project in Tyendinaga Mohawk Territory
Reserve No. 38 and the community of
Shannonville in the Township of Tyendinaga,
Hastings County as described in its
application. The OEB finds that the Project is
the best alternative to meet the need.
To meet the Ontario Government’s NGEP
objective of bringing service to unserved
communities, the OEB provided that the
consideration of such IRP options or
alternatives was not required for NGEP
approved projects that have been designated
in O. Reg. 24/19. The OEB’s decision in this
proceeding is in accordance with its approved
IRP process.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 41 of 97
Page 543
42
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
EB-2022-0249 Hidden Valley
Community
Expansion
Fail As per the IRP Binary Screening Criteria (iv), the need
underpinning the Project does not warrant further IRP
consideration or assessment: iv. Community Expansion &
Economic Development – If a facility project has been driven
by government legislation or policy with related funding
explicitly aimed at delivering natural gas into communities,
then an IRP evaluation is not required.
OEB Decision dated September 21, 2023:
Enbridge Gas Inc. is granted leave, pursuant
to section 90(1) of the OEB Act, to construct
the Project in Township of Huntsville and
District of Muskoka as described in its
application.
The OEB finds that the Project is the best
alternative to meet the need. To meet the
Ontario Government’s NGEP objective of
bringing service to unserved communities, the
OEB provided that the consideration of such
IRP options or alternatives was not required
for NGEP approved projects that have been
designated in O. Reg. 24/19. The OEB’s
decision in this proceeding is in accordance
with its approved IRP process.
EB-2022-0156 Selwyn
Community
Expansion Project
Fail As per the IRP Binary Screening Criteria (iv), the need
underpinning the Project does not warrant further IRP
consideration or assessment: iv. Community Expansion &
Economic Development – If a facility project has been driven
by government legislation or policy with related funding
explicitly aimed at delivering natural gas into communities,
then an IRP evaluation is not required.
OEB Decision dated September 21, 2023:
Enbridge Gas Inc. is granted leave, pursuant
to section 90(1) of the OEB Act, to construct
the Project in the Township of Selwyn as
described in its application. The OEB finds
that the Project is the best alternative to meet
the need.
To meet the Ontario Government’s NGEP
objective of bringing service to unserved
communities, the OEB provided that the
consideration of such IRP options or
alternatives was not required for NGEP
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 42 of 97
Page 544
43
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
approved projects that have been designated
in O. Reg. 24/19. The OEB’s decision in this
proceeding is in accordance with its approved
IRP process.
EB-2022-0157 Panhandle
Regional
Expansion Project
Enbridge Gas reviewed potential IRPA such as firm
exchange between Dawn and Ojibway, a hybrid alternative,
trucked CNG, and an ETEE. These alternatives were found
to not be technically feasible viable solutions.
OEB Decision dated May 14, 2024: Enbridge
Gas Inc. is granted leave, pursuant to section
90(1) of the OEB Act, to construct the Project
in the Municipality of Lakeshore.
The OEB finds that the Project is the best
alternative to meet the forecasted demand
growth on the Panhandle system for the
period November 1, 2024, to the winter of
2028/2029.
EB-2023-0260 Lawrence Ave
East Station
Relocation Project
Fail Fail Enbridge Gas has applied the Binary Screening Criteria and
determined that the need underpinning the Project does not
warrant further IRP consideration based on the timing criteria,
as the need must be met in under three years (the proposed
project has an in-service date of December 2024). In
addition, the Project is driven by a customer-specific build
where Metrolinx will reimburse Enbridge Gas through a
Contribution in Aid of Construction (“CIAC”) for the actual
Project costs.
OEB Decision dated April 18, 2024: Enbridge
Gas Inc. is granted leave, pursuant to section
90(1) of the OEB Act, to construct the Project
in the City of Toronto as described in its
application.
The OEB finds that the Project is excluded
from IRP considerations because Metrolinx
will pay all Project costs. However states that
in future similar application, Enbridge Gas has
to provide clear evidence as to when it
became aware of the project and how IRP
considerations were taken into account in
evaluating project alternatives. This evidence
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 43 of 97
Page 545
44
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
will enable the OEB to assess whether an
identified system need or constraint must be
met under three years.
EB-2023-0175 Watford Pipeline
Project
Fail Enbridge Gas has applied the IRP Binary Screening Criteria
and determined that this Project meets the definition of a
Customer-Specific Build, as defined in the IRP Framework.
The Project is driven solely by a specific customer’s (WM’s)
request for facilities to connect to Enbridge Gas’s existing
natural gas system. WM has executed a long-term contract
including a monthly service charge to be paid by the
Customer.
OEB Decision dated March 7, 2024: Enbridge
Gas Inc. is granted leave, pursuant to section
90(1) of the OEB Act, to construct the Project
in the Municipality of Broke-Alvinston and
Township of Warwick as described in its
application.
The OEB finds that Enbridge Gas has
undertaken an appropriate review of
alternatives and potential routes for the
Project and finds that the proposed route is
the preferred route from an environmental and
socio-economic perspective.
EB-2022-0111 Bobcaygeon
Community
Expansion
Fail Enbridge Gas applied the IRP Binary Screening Criteria and
determined this Project meets the definition of a community
expansion project, as defined in the IRP Framework, as the
Project has been approved by the Government of Ontario for
funding as part of the Phase 2 NGEP. The IRP Framework
explains that “Given the goal of the Ontario Government’s
Access to Natural Gas legislation to extend gas service to
designated communities, the OEB will not require Enbridge
Gas to develop an IRP Plan or consider alternatives to the
infrastructure facilities to meet this need.
OEB Decision dated May 14, 2024: Enbridge
Gas Inc. is granted leave, pursuant to section
90(1) of the OEB Act, to construct the Project
in the City of Kawartha Lakes (including
Bobcaygeon) as described in its application.
To meet the Ontario Government’s NGEP
objective of bringing service to unserved
communities, the OEB provided that the
consideration of such IRP options or
alternatives was not required for NGEP
approved projects that have been designated
in O. Reg. 24/19. The OEB’s decision in this
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 44 of 97
Page 546
45
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
proceeding is in accordance with its approved
IRP process.
EB-2023-0200 Sandford
Community
Expansion
Fail Enbridge Gas applied the IRP Binary Screening Criteria and
determined this Project meets the definition of a community
expansion project, as defined in the IRP Framework, as the
Project has been approved by the Government of Ontario for
funding as part of the Phase 2 NGEP. The IRP Framework
explains that “Given the goal of the Ontario Government’s
Access to Natural Gas legislation to extend gas service to
designated communities, the OEB will not require Enbridge
Gas to develop an IRP Plan or consider alternatives to the
infrastructure facilities to meet this need.
Pending OEB Decision.
EB-2023-0201 Eganville
Community
Expansion
Fail Enbridge Gas has applied the Binary Screening Criteria and
determined this Project meets the definition of a community
expansion project, as defined in the IRP Framework, as the
Project has been approved by the Government of Ontario as
part of the Phase 2 NGEP. The IRP Framework Decision
explains that “Given the goal of the Ontario Government’s
Access to Natural Gas legislation to extend gas service to
designated communities, the OEB will not require Enbridge
Gas to develop an IRP Plan or consider alternatives to the
infrastructure facilities to meet this need.
OEB Decision dated May 30, 2024: Enbridge
Gas Inc. is granted leave, pursuant to section
90(1) of the OEB Act, to construct the Project
in the Community of Neustadt, in the
Municipality of West Grey, as described in its
application.
To meet the Ontario Government’s NGEP
objective of bringing service to unserved
communities, the OEB provided that the
consideration of such IRP options or
alternatives was not required for NGEP
approved projects that have been designated
in O. Reg. 24/19. The OEB’s decision in this
proceeding is in accordance with its approved
IRP process.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 45 of 97
Page 547
46
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
EB-2023-0261 Neustadt
Community
Expansion
Fail Enbridge Gas has applied the Binary Screening Criteria and
determined this Project meets the definition of a community
expansion project, as defined in the IRP Framework, as the
Project has been approved by the Government of Ontario as
part of the Phase 2 NGEP, to provide access to natural gas
services in the community of Neustadt in the Municipality of
West Grey. The IRP Framework Decision explains that
“Given the goal of the Ontario Government’s Access to
Natural Gas legislation to extend gas service to designated
communities, the OEB will not require Enbridge Gas to
develop an IRP Plan or consider alternatives to the
infrastructure facilities to meet this need
OEB Decision dated May 23, 2024: Enbridge
Gas Inc. is granted leave, pursuant to section
90(1) of the OEB Act, to construct the Project
in the Township of Admaston/Bromley, North
Algona Wilberforce and Bonnechere Valley
(including Eganville) as described in its
application.
To meet the Ontario Government’s NGEP
objective of bringing service to unserved
communities, the OEB provided that the
consideration of such IRP options or
alternatives was not required for NGEP
approved projects that have been designated
in O. Reg. 24/19. The OEB’s decision in this
proceeding is in accordance with its approved
IRP process.
EB-2023-0343 East Gwillimbury
Community
Expansion
Fail Enbridge Gas has applied the Binary Screening Criteria and
determined this Project meets the definition of a community
expansion project, as defined in the IRP Framework, as the
Project has been approved by the government of Ontario as
part of the Phase 2 NGEP, to provide access to natural gas
services in the Town of East Gwillimbury. The IRP
Framework Decision explains that “Given the goal of the
Ontario Government’s Access to Natural Gas legislation to
extend gas service to designated communities, the OEB will
not require Enbridge Gas to develop an IRP Plan or consider
alternatives to the infrastructure facilities to meet this need.
Proceeding is currently in progress
(abeyance).
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 46 of 97
Page 548
47
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
EB-2024-0187 Boblo Community
Expansion
Fail Enbridge Gas has applied the Binary Screening Criteria and
determined this Project meets the definition of a community
expansion project, as defined in the IRP Framework, as the
Project has been approved by the government of Ontario as
part of the Phase 2 NGEP, to provide access to natural gas
services in the Town of East Gwillimbury. The IRP
Framework Decision explains that “Given the goal of the
Ontario Government’s Access to Natural Gas legislation to
extend gas service to designated communities, the OEB will
not require Enbridge Gas to develop an IRP Plan or consider
alternatives to the infrastructure facilities to meet this need.
Proceeding is currently in progress.
EB-2024-0141 Ontario Line -
Overlea Station
Relocation Project
Fail Enbridge Gas has applied the Binary Screening Criteria and
determined an IRP evaluation is not required if the need is
underpinned by a customer-specific build. The need for the
Project is driven by Metrolinx and they have agreed to pay a
Contribution in Aid of Construction. Accordingly, the Project is
exempt from further IRP, which is consistent with the OEB’s
decision in related leave-to-construct Projects involving
Metrolinx.
Notwithstanding that an IRP evaluation was not required due
to the customer-specific build criteria, Enbridge Gas
considered supply-side IRPAs for applicability, including
market-based supply and compressed natural gas (CNG). As
the existing pipeline provides natural gas to approximately
400 customers in the Project area, relocation of the pipe is
required to maintain gas services to these customers.
Supply-side alternatives were found to not be feasible and
cannot offset the need for pipe relocation.
Proceeding is currently in progress.
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48
OEB
Proceeding
Docket
Project Name
Binary Screening Results
Enbridge Gas IRP Analysis OEB Regulatory Proceeding Status Customer
Specific
Build
Timing
Community
Expansion &
Economic
Development
EB-2024-0200 St. Laurent
Pipeline
Replacement
Project
As this is a pipeline integrity project, the IRP Analysis for this
project was limited to whether the proposed pipeline size can
be reduced, as neither a supply side or demand side
alternative would adequately address the corrosion and third
party damage risk. Enbridge Gas reviewed potential IRPA
such as incremental gas supply, trucked CNG, ETEE and for
contract customers to de-contract or convert existing firm
service to an interruptible service. These alternatives were
found to not be technically feasible or viable solutions.
Proceeding is currently in progress.
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49
Appendix E: Technical Working Group Report
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Page 551
Review of Enbridge Gas
Inc. 2023 Integrated
Resource Planning (IRP)
Annual Report and Update
on IRP Working Group
Activities
From: Integrated Resource Planning
Technical Working Group
July 2, 2024
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Contents
1. Introduction and Overview of IRP Working Group.......................................................................... 3
1.1. Overview and Membership of IRP Working Group ................................................... 3
2. Review of Enbridge Gas’s Annual IRP Report and Comments on IRP Framework
Implementation ..................................................................................................................................... 6
2.1. Working Group Comments on the Implementation of the IRP Framework ........... 7
3. Description of Key Working Group Activities ................................................................................. 23
3.1. IRP Pilot Evidence........................................................................................................ 25
3.2. DCF+ Test and Guide .................................................................................................. 27
3.3. Policy Proposals for Non-Pilot IRP Plan ................................................................... 28
3.4. IRP Assessment Process and Demand Forecasting .............................................. 31
4. IRP Priorities and Working Group Activities in 2024 .................................................................... 32
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1. Introduction and Overview of IRP Working Group
The Ontario Energy Board (OEB) established a first-generation Integrated Resource Planning
(IRP) Framework for Enbridge Gas through its July 22, 2021 Decision and Order (IRP Decision).
The IRP Decision directed the OEB to establish an IRP Technical Working Group (Working
Group) and requires a Working Group report to be filed in the same proceeding in which
Enbridge Gas’s annual IRP report is filed. The Working Group was formed and announced in a
letter issued by the OEB on December 6, 2021, and has been active since then.
This Working Group report provides:
• The Working Group’s review of Enbridge Gas’s Annual IRP Report and comments on
Enbridge Gas’s implementation of the IRP Framework in 2023 (as described in
Enbridge Gas’s 2023 Annual IRP Report), including individual member comments or
concerns. (Chapter 2)
• A summary of activities undertaken by the Working Group over the previous year, from
the time of the previous Working Group report (May 30, 2023) up until the issuance of
this year’s report on July 2, 2024. (Chapter 3)
• The Working Group’s views on priorities for implementation of the IRP Framework in
2024, and the Working Group’s expected role. (Chapter 4)
The Working Group report was prepared by OEB staff with input from all current Working Group
members and approved by them as an accurate summary of the Working Group’s activities.1
This report clearly indicates where opinions expressed in the report do not reflect the views of
all members.
1.1. Overview and Membership of IRP Working Group
The Working Group was established to provide input on IRP issues that will be of value to both
Enbridge Gas in implementing IRP and to the OEB in its oversight of the IRP Framework.
Members of the Working Group were determined through a call for nomination process where
the OEB selected non-utility members, representatives from the OEB and Enbridge Gas, and
1 The IRP Technical Working Group includes observers from the Independent Electricity System Operator and EPCOR Natural Gas LP. As noted in the Working Group’s Terms of Reference, any materials authored by the IRP Working Group (including this report) should not be considered to represent the views of Working Group observers, or their organizations.
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4
observers from the Independent Electricity System Operator (IESO) and EPCOR Natural Gas
LP.
There were several Working Group member changes over the past year. Non-utility member
Amber Crawford resigned from the Working Group after leaving her position at the Association
of Municipalities of Ontario (AMO) in June 2023. Spencer Sandor from AMO temporarily
replaced Amber Crawford on the Working Group. However, AMO will be stepping back from
having an employee participate as a regular member of the Working Group and will instead
remain available as a resource to provide a municipal perspective to the Working Group as
needed. Jennifer Murphy and Allison Moore replaced Chris Ripley as Enbridge Gas
representatives in early 2024. Whitney Wong also remains an Enbridge Gas representative on
the Working Group.
Table 1: Current IRP Working Group Membership
Name Role
Michael Parkes
OEB staff
representative (Working Group chair) Stephanie Cheng OEB staff representative
Whitney Wong Enbridge Gas representative
Jennifer Murphy Enbridge Gas
representative
Allison Moore Enbridge Gas representative
John Dikeos, ICF Consulting Canada Inc. Non-utility member
Tamara Kuiken, DNV Inc. Non-utility member
Cameron Leitch, Enwave Energy Corporation Non-utility member
Chris Neme, Energy Futures Group Non-utility member
Dwayne Quinn, DR Quinn & Associates Ltd. Non-utility member
Jay Shepherd, Shepherd Rubenstein Professional Corporation Non-utility member
Kenneth Poon, EPCOR Natural Gas LP Observer
Steven Norrie, Independent Electricity System Operator Observer
Meeting notes and materials for all IRP Working Group meetings are published on the OEB’s
website following meetings to document key discussion points and to allow stakeholders to
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5
follow the Working Group’s progress.2 These materials can be found at:
https://engagewithus.oeb.ca/irp
2 Meeting materials are typically posted online shortly after the meeting. Meeting notes are not typically posted until after the following meeting, to allow for members to review draft notes and identify any omissions or inaccuracies.
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2. Review of Enbridge Gas’s Annual IRP Report and
Comments on IRP Framework Implementation
Per the IRP Decision, the Working Group is expected to review a draft of Enbridge Gas’s annual
IRP report. The review is coordinated by OEB staff.
Enbridge Gas is expected to provide the Working Group with a draft of its annual IRP report far
enough in advance of its planned filing to the OEB to allow the Working Group adequate time to
review and comment. The IRP Decision also stipulates that the Working Group report should
include any comments on Enbridge Gas’s annual IRP report, including material concerns that
remain unresolved within the Working Group.
Consistent with the prior year, the Working Group’s review took the following steps:
STEP 1:
STEP 2:
STEP 3:
Provided a draft of its 2023 IRP annual report to the Working Group for review.
Enbridge Gas
Provided suggested edits/ comments/ clarifying questions.
Working Group Members
Revised and finalized its annual report. • Enbridge Gas discussed member comments at the June 5 meeting. • Enbridge Gas subsequently finalized its annual report, documenting how it addressed comments from Working Group members. Members had the opportunity to ask any follow-up questions at the June 19 meeting. Final determinations as to the contents of Enbridge Gas’s IRP annual report were made by Enbridge Gas, not the Working Group.
Enbridge Gas
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STEP 4:
2.1. Working Group Comments on the Implementation of the IRP Framework
Working Group members (except observers) were asked the following question:
Having reviewed Enbridge Gas’s description of Enbridge’s IRP activities in the
previous year in its final 2023 IRP annual report and having also participated in
the IRP Working Group, do you have any comments and/or concerns with the
implementation of the IRP Framework to date? What do you think should be the
highest priorities for the implementation of the IRP Framework in 2024?
Working Group members generally expressed frustration and concerns with the pace of
Enbridge Gas’s IRP project implementation (particularly the pilots, but also the lack of projects
to displace facility spending). Some Working Group members believe the IRP screening and
evaluation process has been too strict or inflexible. Although Working Group members
acknowledge that Enbridge Gas has made progress in building IRP capacity and processes;
some members noted that the lack of IRP project activity and results suggests that the success
of IRP may not be an important overall internal priority for Enbridge Gas as a whole.
Comments provided by individual members can be found below in Table 2.
Comments from Enbridge Gas Working Group members follow in Table 3.
Priorities for 2024 are further discussed in Chapter 4 of this report.
Provided final individual comments on implementation of the IRP Framework including the highest priority items for 2024, for inclusion in the Working Group report. Member comments are discussed further below in Section 2.1.
Working Group Members
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Table 2: Individual Comments of IRP Working Group Members
Working Group
Member Comments (optional)
John Dikeos
(non-utility member)
Based on information that Enbridge has shared in its 2023 IRP annual
report and in the regular TWG meetings over the past year, they have
demonstrated progress on a number of fronts related to the
consideration of IRP alternatives and the broader implementation of
the IRP framework. However, progress has been disappointingly slow
in some areas. For instance, despite the submission of an IRP pilot
application in July 2023, the approval and implementation of any IRP
pilot is still in limbo. Although some of the delays have been out of
Enbridge’s control, the timeline for next steps is uncertain nearly a year
later and, based on progress to date, it seems unlikely that Enbridge
will be able to start implementing any IRP pilots in time for the
2024/2025 heating season.
Given the timeline required to gather and analyze data from n any
pilots once they are in the field, Enbridge is still years away from
collecting and deploying valuable learnings on the implementation of
enhanced EE programs and gas DR initiatives. This is a missed
opportunity since the whole point of implementing IRP pilots was to
collect practical experience with the implementation of IRPAs on an
expedited basis to allow Enbridge staff to more accurately and
effectively estimate costs and impacts on a broader scale. Most
importantly, this will help reduce the risks associated with the
implementation of IRP projects.
The highest priorities for the implementation of an IRP framework in
2024 should be the implementation of IRP pilots in advance of the
pending heating season and the continued development of a DCF+
test and supplemental handbook so that IRP projects can be
considered on a fair and consistent basis. Enbridge is encouraged to
seek out opportunities to fast-track the regulatory approval process for
IRP pilots. Enbridge should also continue monitoring relevant progress
in other jurisdictions across North America.
Tamara Kuiken
(non-utility member)
Over the last two years, Enbridge has shown a lack of agility in
implementing IRPAs that I find surprising. To be fair, there have been
unanticipated and adjacent issues that derailed portions of the process,
but it’s disappointing that we don’t have a concrete schedule for
implementing an IRPA, not even an enhanced targeted energy
efficiency (ETEE) program which is simply an extension of existing
services. While I cannot speculate on the cause of the delay, it seems
clear that IRPA is not a high priority within the organization.
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I feel it is crucial that an ETEE pilot be in the field during the 2024-2025
heating season to provide the learnings necessary for reliable IRPAs to
be implemented in the future. It’s vital to prove the concept of ETEE as
a long-term IRPA solution, or prove its ineffectiveness so new
alternatives can be developed.
Cameron Leitch
(non-utility member)
To echo comments by other TWG members, I believe that progress
has been slow given the amount of effort and time that has passed
since the OEB Decision. Further, I believe that the proportion of IRPA
that advance passed binary screening and technical evaluation should
be at least meaningful; the fact that 28 out of almost 4,300 projects met
the technical evaluation criteria (per Enbridge's draft IRP Annual
Report) suggests that the process is not working.
A cursory review of the updated Appendix B from the AMP
(https://www.rds.oeb.ca/CMWebDrawer/Record/820703/File/document)
yielded the following:
• The highest value projects have been screened (and most
passed) to the technical evaluation stage. Focusing on high
value projects first when there are so many in the AMP is
sensible. That said, approximately 2/3 of the more than 3,300
projects listed failed binary screening based on the "dollar
threshold" criterion. Of these, 48 had a forecast spend of
greater than $2M (totaling more than $300M combined), 241
had a forecast spend of greater than $1M ($560M combined),
and 497 had a forecast spend greater than $500k (totaling
$750M). Aside from the fact that Enbridge's screening process
identified a $2M threshold and almost 50 projects were above
this amount, there appears to be a considerable opportunity in
projects that have been screened out purely on project cost.
• Enbridge's screening process eliminates projects where the
need must be met within 3 years. There are approximately 120
projects that meet this criterion, totaling approximately $275M.
Of these, 24 do not have any value assigned. There appears to
be an opportunity to at least tier the limit on timing based on
spend (i.e., assign a lower time limit when spend is lower), but
the main concern is all the future projects that may get
screened out while the process is being refined. For example,
there are nearly 500 projects in the AMP within service dates in
2026 and 2027 totaling nearly $1.5B. It is encouraging that of
these, 131 projects totaling nearly $1.4B have passed binary
screening, but only 15 have passed technical evaluation
(totaling approximately $11M). When the AMP is filed in
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10
subsequent years, there is risk that many of these projects will
be screened out due to timing.
• There isn't any justification provided for projects that have failed
binary screening, beyond the category that the justification falls
into. This equates to approximately $1.4B work of project
scope. The rationale for projects that fail binary screening is
opaque. For example, investment code 48290 is a $15.5M
project that failed for "dollar threshold", but there isn't any
further justification that I can find. Provision of "investment
summary reports" like those provided for projects which past
binary screening in the 2022 rebasing application would be
helpful.
I would like to see considerable progress in the advancement of IRP
processes and in the selection of IRPA, otherwise we will continue to
miss opportunities. The DCF+ Guide will help describe how Enbridge
intends to assess projects which make it past binary screening and
technical evaluation, but given the quantity of screened-out projects,
some insight into the initial stages of assessment would be valuable in
order for the TWG to provide feedback and suggestions.
During the TWG meetings, both early in the establishment of the group
and more recently during discussions of "Phase 2" (system pruning),
there have been solutions proposed that involve Enbridge providing
more than delivery of gas to the customer, such as heat pumps and
geoexchange. These discussions have revolved around the
implementation of non-pipe solutions, even if "electrified" solutions,
during the IRP pilots to gain valuable knowledge and experience with
IRP. Although I am interested in the potential learnings, electrification-
based IRP isn't within the mandate of this group, and including these
sorts of efforts within the purview of a rate-regulated utility is a slippery
slope. It would be inconsistent for Enbridge to incentivize efforts like
attic insulation instead of performing the work itself but self-perform the
installation of heat pumps or other systems that would reduce peak
demand instead of incentivizing. Rate-basing these types of projects
would create a non-competitive environment.
In closing, in 2024 and beyond, I would like to see a focus on full and
transparent assessment of projects for IRP, completion of all guides
and processes (such as the DCF+ guide), and (hopefully) the
identification of a meaningful number of candidate projects through to
execution of IRP.
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Chris Neme
(non-utility member)
I share the concerns of many other Working Group members regarding
lack of progress on IRPAs. While it does seem that Enbridge has
made progress in adding capacity and institutionalizing assessments of
IRPAs, the fact that we do not have IRPA projects in the field today –
roughly three years after the Board’s Decision and two and a half years
after the launch of the IRP Working Group – is very disappointing. It is
particularly problematic that the promised pilot IRPA projects have not
been launched and probably won’t be before the 2024-2025 heating
season (meaning another year of important peak period data collection
will be lost). The whole point of pilots is to learn by doing. Moreover,
particularly in the context of more geographically targeted efficiency
IRPAs, where the other benefits (energy cost reductions for customers,
greenhouse gas emission reductions, etc.) would probably outweigh
the costs even without any IRPA learnings, the pilots should have been
considered “no regrets” initiatives. Instead, it feels as if the pilots have
been analyzed, revised, refined, reassessed, and revised and reviewed
again and again. Put simply, it feels as if Enbridge has let “the perfect
be the enemy of the good”.
Also, the fact that, other than Kingston, no non-pilot IRPA projects
have been proposed by Enbridge suggests that there is a problem with
the screening process. As Cameron alluded to above, it may be that
the $2 million threshold for even considering a project is too high. A
related point is that the Board’s decision to exclude electrification as an
IRPA option needs to be revisited. I say that for several reasons. First,
electrification offers the potential for much larger peak load reductions
than other IRPA options, so allowing it to be part of a package of
options should expand the range of potential projects. Second, other
jurisdictions, such as New York and California, are proceeding with
electrification as prominent parts of non-pipe solutions. Third, we know
that electrification of significant load is going to be required as part of
the “energy transition”, so including it in IRPA’s provides significant
additional benefits.
Finally, I have been frustrated by the lack of progress in refining the
DCF+ cost-effectiveness test. Progress was made initially through
some good Work Group discussions, but several key issues never got
resolved. Enbridge has suggested it will file its revised DCF+ approach
in its next IRPA filing, but we have no idea when that will be.
Moreover, in my view, it is much better to work these arcane and
challenging issues out ahead of time, without the pressure of a
regulatory proceeding. Instead, we are still in limbo on a number of key
issues.
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Given all the above, my priorities for IRP Framework progress in 2024
are: (1) get the pilots launched ASAP, ideally before the start of winter;
(2) have more intensive and concentrated discussions of outstanding
DCF+ issues so that we can reach agreement, if possible, and clearly
document where and why disagreement is not possible; (3) revisit key
framework decisions – including both the exclusion of electrification
measures and the $2 million threshold – to develop group
recommendations, if possible, on what changes make sense and could
lead to more robust implementation of cost-effective IRPA’s; and (4)
begin discussion of design and launch of a system pruning pilot,
consistent with the Board’s recent order in the rebasing case.
Note that the scope of the priorities in front of us may necessitate some
smaller “subcommittees” of the Work Group to meet more often to
develop drafts for the larger group to consider. Meeting as a large
group once or twice a month may simply not be enough.
Dwayne Quinn
(non-utility member)
Being the last member to enter my comments, I have had the benefit of
reviewing the comments of my fellow non-utility members of the
Working Group. Not surprisingly, the themes of concern and
disappointment with the lack of progress in developing and
implementing IRP are a constant theme. I support these consensus
opinions and, without reiterating, say Enbridge Gas’ lack of
collaboration has contributed to these concerns and lack of results.
Upon review of EGI comments, I would like to add that Exhibit A of the
lack of collaboration is the Municipal Information & Data Request
Summary for Gas Infrastructure System Planning. This three-page
document outlines the information that EGI is seeking from
municipalities to support the company’s assessment of the future
demand for gas in the community. Version 1 of the document dated
October 1, 2023 was provided to the TWG after its existence was
noticed by TWG members in reading EGI’s annual report. EGI neither
sought input from the TWG nor even spoke to their initiatives with
municipalities including this document. I was prompted to add this in
reviewing the “progress” EGI noted in their comments on the technical
evaluation process in their work with “key internal stakeholders”
when little of the content of these process changes has been shared
with the TWG for our opportunity for input.
One area that has not been touched on much in the comments by
other members is supply-side IRPA. This aspect of IRP was
highlighted in trying to meet the needs of Parry Sound. From the
outset, I attempted to work with the larger group and more directly with
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select Enbridge Gas staff to develop supply-side and bridging solutions
that would meet the needs of the community while providing valuable
learning opportunities as a pilot. In spite of my willingness to assist,
information was provided by Enbridge Gas only after the information
had gone through internal processes which slowed progress and
inhibited collaboration.
With recent changes in the Enbridge Gas demand forecasting, the
once urgent needs of the Parry Sound community have disappeared in
such a way that even the piloting of CNG, which would have import into
other bridging solutions, has been dropped. While I am encouraged
that Enbridge has evolved its demand forecasting (which needs to be
understood better), it is disconcerting that there was not another
project waiting in the wings to be able to apply supply-side solutions
including CNG for the opportunity to learn by doing not by studying.
Without another suitable system identified by Enbridge Gas for
implementation of supply-side solutions, the group is unable to achieve
a significant section of its mandate, likely resulting in missed
opportunities and risks of future stranded assets.
One important aspect did come from our work on Parry Sound. There
is an Enbridge Gas bias to meeting customer demand by adding
pipeline capacity as opposed to looking at flow and pressure control
from pressure-reducing stations. In Parry Sound, a marginally small
investment in improving station equipment can be much more
economic than the comparable capacity available from a pipeline. I
believe that station work should be considered a component of supply-
side IRPA’s as it has been identified in other jurisdictions. While
Enbridge Gas has expressed its preference that station work be
considered part of their normal operations, my experience with the
Parry Sound project informs my ardent belief that this valuable solution
could be missed if not identified and highlighted as part of any IRP
process.
Jay Shepherd
(non-utility member)
In my comments on the 2022 Annual Report, I estimated that,
shockingly, it was unlikely that Enbridge would implement IRP projects
displacing more than 1% of the $7 billion of capital spending proposed
in its five-year Asset Management Plan. The first year of that AMP
(since revised) is halfway gone, and zero projects have even been
identified that would displace any facilities spending. Currently, the
best estimate for reductions in capital spending due to IRP in the
period 2024-2028 is zero.
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This is but one example of the unreasonable delays that have plagued
IRP since Enbridge was ordered to implement it three years ago. The
most glaring example is the OEB’s direction that the first IRP Pilots be
deployed by the end of 2022, as Enbridge itself had proposed. It now
appears clear that the pilot or pilots, if any, will be deployed in 2025, at
the earliest, and will not displace any facilities spending.
The term “ragging the puck” refers to a strategy in which a team makes
it appear they are playing hockey, but they are not. They are only
really using up time to achieve their real purpose: delay. An objective
observer might legitimately see the Enbridge approach to IRP as
ragging the puck.
That may in fact be unfair. It is equally possible that Enbridge is
simply struggling to figure out how to evolve their asset management
process to incorporate effective IRP. This evolution is complicated by
at least the following:
1. Asset Management at Enbridge is only minimally supervised by
external forces, such as the OEB. It is treated as an internal, highly
iterative process where continually changing priorities and budget
realities are subject to immediate responses that require no regulatory
processes. IRP, at least at this stage, is under the microscope at all
times. Further, those who manage assets have tried and true
responses on which they rely during this iterative process, which don’t
include IRP.
2. The 2021 Decision establishes a set of guidelines that Enbridge has
treated as basically immutable and hard-wired into the process. This
creates a multi-step screening and evaluation process for IRPAs that
prevents the integration of IRP into the asset management process.
3. At the same time as the OEB is requiring Enbridge to implement
IRP, Enbridge is in parallel lobbying government to give it greater
freedom to expand its distribution infrastructure. This creates the
constant hope that, whenever the OEB orders that Enbridge slow down
the pace of rate base growth, the government will step in and allow the
utility to speed it up.
4. The Energy Transition is a change of massive proportions for
Enbridge, affecting all forecasting. Since forecasting peak demand for
a number of years out, sometimes at a granular level, is central to
effective IRP, the uncertainties and declining growth assumptions
arising out of the Energy Transition make it more difficult to implement
IRPAs with confidence that facilities spending will be reduced. For
example, each proposed facilities project discussed by the working
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group has subsequently been delayed and moved out of the ten-year
AMP due to revised forecasts.
5. There are no North American utilities that are well advanced in
implementation of gas IRP, and the models from electricity IRP are
only partially helpful. Since much of utility planning is about
implementing “best practices”, Enbridge is challenged where there are
not yet any obvious best practices from other jurisdictions that have
been shown to work.
All of this brings the focus to a key issue in IRP planning right now.
Enbridge is still seeing as “progress” steps that are entirely about
talking and thinking and considering options, and does not appear to
see a distinction between those steps, and real actions producing real
outcomes. We have had a long period of talking, but nothing has
actually happened. Further, there is no current plan for any actual
IRPAs to happen.
This would not be acceptable in any other area of the Enbridge
business, nor is it a good management approach in any business,
utility or otherwise. At some point, you have to shift the focus from
talking to doing.
The top priority in 2024 – and this may in June 2024 be wishful
thinking, of course – should be to actually implement one or more
IRPAs and, in the process, delay or replace facilities spending. This
will necessarily mean having imperfect information on which to base
the planning (nothing new in facilities cases), but proceeding with some
IRPAs anyway.
This will not happen, certainly, unless the OEB steps in and orders
Enbridge to move in this direction. If no sense of urgency is created –
which really only the regulator can do – then Enbridge will continue to
struggle with the challenges described above (or, more cynically,
continue to rag the puck and delay the implementation of IRP).
Mike Parkes/
Stephanie Cheng
(OEB staff
representatives)
Enbridge Gas has made significant progress towards integrating IRP
into its business operations, as documented in Appendix A of Enbridge
Gas’s annual IRP report. However, this has not yet translated into IRP
projects except for the small Kingston project. The filing of Enbridge
Gas’s IRP pilot application in July 2023 was a major milestone, as
these pilots are expected to provide on-the-ground learnings regarding
future IRP design, performance and potential for scalability. The
subsequent delays in moving the IRP pilot projects through the
regulatory approval process have been disappointing, although this
been due at least in part to changing circumstances outside of
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Enbridge Gas’s control (e.g., loss of matching federal grant funding).
OEB staff believes that Enbridge Gas has engaged the Working Group
appropriately during proceeding abeyances by seeking and
incorporating feedback regarding the redesign of the pilots.
OEB staff generally agrees with the 2024 priorities identified by
Enbridge Gas within its IRP Annual Report (section 10). OEB staff
believe that advancing the IRP pilot projects through the regulatory
approval process and, should the OEB grant approval, proceeding
rapidly to implementation should be Enbridge Gas’s highest priority.
OEB staff offers the following suggestions on two additional identified
priorities:
• Discounted Cash Flow-Plus (DCF+) Test: Enbridge Gas
indicates it will file a submission on the DCF+ test as part of its
first non-pilot IRP Plan application. However, Enbridge Gas has
postponed that application indefinitely as a result of updates to
Enbridge Gas’s System Reinforcement Plan (section 6 of
Enbridge Gas’ IRP Annual Report). OEB staff recommends
that Enbridge Gas prioritize completing the DCF+ test and
guide in 2024, given that this was an identified priority in the
IRP decision, and is intended to be used in both IRP Plan
applications and Leave to Construct applications (in
circumstances where Enbridge Gas determines that a facility
project is preferable to an IRP Plan, taking into account the
results of the DCF+ analysis). There may be opportunities to
initiate the OEB’s formal review of Enbridge Gas’s DCF+ test
and guide in advance of a non-pilot IRP Plan application, such
as during one of the aforementioned Leave to Construct
applications. As such, it makes sense to finalize this component
so that Enbridge Gas is in position to file at the first available
opportunity.
• Continued IRP Evaluations: During the Panhandle Leave to
Construct proceeding (EB-2022-0157), OEB staff noted the
importance of ensuring adequate lead time for a detailed
consideration of IRP alternatives, given the longer time needed
for demand-side alternatives to deliver their full demand
reduction potential. With less projects suitable for IRP
remaining in Enbridge Gas’s 10-year Asset Management Plan
(AMP) as a result of forecasting changes, Enbridge Gas should
be able to devote more effort to proactive consideration of IRP
alternatives for the higher-cost projects that do remain in the
AMP. This should include the remaining projects identified in
Appendix C as well as major transmission projects (growth and
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non-growth) and major non-growth distribution projects that
remain in the AMP, which are not shown in Appendix C. For
non-growth projects, Enbridge Gas should consider both asset
life extension alternatives and IRP alternatives.
Table 3: Comments of Enbridge Gas IRP Working Group Members
Working Group Member Comments (optional)
Jennifer Murphy/
Allison Moore/
Whitney Wong
(Enbridge Gas representatives)
2023 represented a year of significant progress in the
implementation of the IRP Framework and Enbridge Gas
has valued the engagement with the TWG members
based on their technical expertise. Enbridge Gas made
strides in institutionalizing the assessment of non-pipeline
alternatives and added resources to focus on IRP in
2023. TWG members have expressed concerns
regarding the process and focus for IRP within Enbridge
Gas, the pace of IRP Pilot implementation, non-Pilot IRP
Plan implementation, and finalization of the DCF+ test
and supplemental guide.
Enbridge Gas outlined its 2023 IRP activities within the
Company’s 2023 IRP Annual Report, and provides
comments below to address the key concerns noted by
TWG members above:
IRP Evaluation Process
Implementing IRP into a utility’s established asset
management planning process is complex and time
intensive. As noted by a TWG member in their
comments, there are no North American utilities that are
well advanced in the implementation of natural gas IRP,
and the models from electricity IRP are only partially
helpful. 2023 represented a significant year for advancing
the implementation of IRP evaluation in this complex
process. Enbridge Gas completed screening for all
projects in the 2023 – 2032 Asset Management Plan,
which was a total of 4,281 investments. For the screening
stages in the IRP evaluation process, Enbridge Gas
conducts project scope verification in relation to the
screening criteria at the associated stage of the process.
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• The initial screening stage was completed for all
4,281 investments.
• The binary screening stage was completed for all
investments that screened to this stage, which
represented 3,332 investments.
• The technical screening stage was completed for
all investments that screened to this stage, which
represented 1,036 investments.
• A technical evaluation was completed for 141
investments in 2023 that screened to this stage.
The technical evaluation stage can be a rigorous
and time intensive process to conduct network
modelling of customer demands and demand
reductions required to meet system needs. Of the
141 investments, 63 passed technical evaluation.
Investments are reviewed on an annual basis to ensure
scope and timing changes are reflected in the IRP
Evaluation.
Enbridge Gas made meaningful progress on the
integration of IRP into the Asset Investment Planning
Management (AIPM) process since the filing of the first
Appendix B update on October 31, 2022, as part of EB-
2022-0200, Exhibit 2, Tab 6, Schedule 2. Specifically, in
2023, Enbridge Gas continued to pursue IRP integration
into the AIPM process through updates to the IRP
evaluation process and Copperleaf (asset investment
planning tool) allowing for IRP Binary Screening as well
as investment review for IRP applicability earlier in the
AIPM process and documentation of IRP evaluation
results. Full implementation of this change will be
completed in 2024.
Enbridge Gas identified learnings in 2023 to streamline
and improve the existing technical screening process, as
outlined in Appendix G of its 2023 IRP Annual Report.
This technical screening guide was created to guide and
document the technical screening stage which has been
introduced. This built upon the IRP screening and
evaluation process in the OEB IRP Framework.
In the development of the technical evaluation stage of
the process, collaboration with key internal stakeholders
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resulted in the creation of technical evaluation forms.
These forms are used to assess the technical feasibility
of IRPAs to eliminate, reduce or defer a project need. The
results of the technical evaluation are documented
through the technical evaluation form and are
communicated to key internal stakeholders, ensuring that
the most up-to-date information is used across the
organization. This ensures that the most optimal
alternative is implemented.
Additionally, Enbridge Gas seeks to maintain this
continuous improvement approach to integrate learnings
and update the process to reflect the latest IRP
Framework requirements and changes to the energy
transition landscape while consulting with the TWG for
feedback and awareness. Subsequently, evolution of the
IRP evaluation process will be reflected in the AIPM
Process.
Enbridge Gas will continue to engage the TWG regarding
process enhancements and documentation to ensure the
process is clear to all parties and can be optimally
informed by their technical expertise.
IRP Pilot Projects
Development of the pilots was a key focus for Enbridge
Gas as well as for the TWG in 2023. An overview of the
work Enbridge Gas undertook in 2023 on the IRP Pilots
has been highlighted in Section 4 of the Company’s 2023
Annual Report.
Throughout 2023, Enbridge Gas continued to engage the
TWG regarding the pilot projects to seek advice on
various aspects of the application including the scope of
the ETEE/DR programming, incentive levels, new
measures/offerings, data collection and evaluation,
budget thresholds, cost benefit analysis, and cost
recovery methodologies.
Enbridge Gas made every effort to incorporate feedback
received from the TWG into the final design of the pilot.
The TWG was generally supportive of most elements and
the Pilot Projects Application was filed July 19, 2023.
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The Pilot application has been delayed due to various
factors since the initial filing in July 2023, including the
announcement from NRCan to halt intake of new entrants
into the Greener Home Grant in November 2023 and
more recently, updates to the system reinforcement plan
(SRP) as well as energy transition and demand forecast
adjustment updates in early 2024. These changes
resulted in the need to revisit and revise the pilot scope
and application. Enbridge Gas engaged the TWG in
March 2024 prior to the SRP and energy transition
adjustments updates to proactively consult on the optimal
path forward. In consultation with the TWG, Enbridge Gas
confirmed a revised approach for the Pilot Project in April
2024 to ensure the Pilot Project application and evidence
update could be filed as quickly as possible by June 28,
2024. Enbridge Gas also ensured that the design of the
updated Pilot Project is structured to enhance annual
participation and maintain 2027 as the last year of the
pilot to ensure the timeline for key learnings and final
reporting is maintained as per the original July 2023
application, despite delays in the launch of the Pilot.
Enbridge Gas has taken proactive steps, where possible,
to initiate certain activities that are anticipated to require
longer lead times, in efforts to reduce any delays in the
implementation of the pilots upon receiving a decision
from the OEB. These activities include installation of
residential hourly measurement, collection of hourly data
where available (through both automated and manual
reads), initial analysis of data quality from hourly reads,
exploration of options for installing hourly measurement
devices on both residential and larger
commercial/industrial customers at scale, surveying
potential land options for CNG injection, and preparation
of documents for anticipated third-party
contracting/supply-chain processes. Enbridge Gas also
facilitated project-specific engagement sessions within
each of the initially proposed pilot areas to solicit
feedback from the communities and to test potential
engagement channels for future initiatives, and has
ensured interested stakeholders and Municipal staff have
remained informed on the status and adjustments to the
Pilot Projects in 2023 and 2024.
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Enbridge Gas shares the TWG’s desire to be in a position
to launch the Southern Lake Huron Pilot Project as
quickly as possible. Enbridge Gas remains hopeful that
an OEB decision can be issued in 2024 to allow for
market launch as soon as possible to begin to learn from
the pilot.
Non-Pilot IRP Plan
Enbridge Gas did not file a non-Pilot IRP Plan given the
impacts of the SRP update as summarized in Section 3 of
the Company’s 2023 IRP Annual Report. As outlined in
Section 6 of that Report, Enbridge Gas was moving
forward with an IRP Plan for the Owen Sound
reinforcement project including having initiated
stakeholder engagement sessions with representatives of
the municipalities, electric LDCs, Hydro One and the
IESO, and having implemented an In-Franchise Binding
Reverse Open season in the area of influence for the
project. However, the timing of the project was shifted
from 2025 to 2031 as a result of the impacts of the SRP
update and therefore the development of the IRP Plan for
this project has been put on hold.
Enbridge Gas is continually evolving its system models to
reflect best available information and forecasted system
constraints, as is prudent to ensure the Company’s
demand forecast and 10-year capital plan continually
reflect current information. This process has shifted the
timing of some investments in the 10-year capital plan
which has in-turn impacted the IRP evaluation of the
projects. Enbridge Gas has implemented the screening
and evaluation process from the IRP Framework
appropriately and is working through reviewing near-term
investments to determine viable IRP Plans for
implementation.
DCF+ Test
Throughout 2023, Enbridge Gas made progress towards
enhancing the DCF+ test in consultation with the TWG as
outlined in Section 9 of Enbridge Gas’s 2023 IRP Annual
Report. After significant consultation on the DCF+ test,
including a presentation of the DCF+ on the potential
Parry Sound pilot on January 10, 2023, the TWG
released the “Use of the Discounted Cash Flow-Plus Test
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in IRP: Report of the IRP Technical Working Group,” on
May 30, 2023 documenting the TWG’s key
considerations to enhance the DCF+ Test, including the
creation of a supplemental guide. Enbridge Gas agreed
and shared the first draft of the resulting DCF+
Supplemental Guide with the TWG on September 26,
2023 for comment.
Enbridge Gas continued to consult with the TWG at the
October 3, November 28, and December 12, 2023 TWG
meetings. TWG meetings on key issues identified in the
DCF+ Supplemental Guide included but was not limited
to input assumptions, categories of costs/benefits, and
summation of phases. Enbridge Gas further provided a
working Excel version of the DCF+ test using an example
to demonstrate the mechanics of the DCF+ test on
November 24, 2023, in advance of the November 28,
2023 TWG meeting. Enbridge Gas walked the TWG
through the DCF+ test example and requested additional
written feedback by the TWG for consideration.
Enbridge Gas continues to refine the DCF+ Test and
Supplemental Guide and will be sharing an updated
version of the Supplemental Guide for review and
comment by the TWG in 2024 prior to filing the DCF+ test
with the OEB as part of the Company’s first non-pilot IRP
Plan. Enbridge Gas agrees that finalization of the DCF+
test is a priority and will make efforts to finalize the DCF+
test and Supplemental Guide efficiently in consultation
with the TWG.
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3. Description of Key Working Group Activities
Per the IRP decision and consistent with the Working Group’s Terms of Reference, the highest
priorities for the Working Group were identified as:
1. Consideration of IRP pilot projects to better understand how IRP can be implemented to
avoid, delay, or reduce facility projects.
2. Enhancements or additional guidance in using the DCF+ economic evaluation
methodology to assess and compare the costs and benefits of using either facility
solutions or IRP alternatives to meet system needs.
The Working Group’s initial role in contributing to these items was largely completed by mid-
2023 with the completion of the Working Group report on the Discounted Cash-Flow Plus test
(May 30, 2023) and Enbridge Gas’s filing of its IRP Pilot Projects application (July 19, 2023).
Additional 2023 priorities were identified in Enbridge Gas and the Working Group’s 2022 IRP
Annual Report. After further discussion with the Working Group, Enbridge Gas proposed a high-
level work schedule that outlined meeting topics and timelines that were generally accepted by
members. This included IRP policy considerations for Enbridge Gas’s first non-pilot IRP plan
application, as well as other topics of interest previously identified by working group members,
such as the IRP assessment process (including the results of Enbridge Gas’s AMP update) and
updates on IRP progress in other jurisdictions.
All of these topics have been subsequently discussed with the Working Group. There were
some changes to the schedule and items discussed by the Working Group as the year
progressed due to several changes impacting the IRP pilot application and implications arising
from OEB’s decision on Enbridge Gas’s rebasing application in December 2023.
A high-level summary of each topic is provided in the subsections below. Readers can refer to
the meeting folders on the OEB’s Engage with Us (EwU) IRP webpage3 for meeting materials
and meeting notes summarizing key discussion points and outcomes. Refer to Table 4 below for
a summary of meeting dates and key topics discussed at each meeting.
3 https://engagewithus.oeb.ca/irp
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Table 4: Summary of Meeting Dates and Key Topics Discussed
Meeting Date Key Topics Discussed
June 20, 2023 • Pilot Evidence
• 2023 Priorities
• IESO Non-Wires Guide
October 3, 2023 • Regulatory Update and Fall Workplan
• IRP Plan Development (Key Topics and Timeline)
• DCF+ Guide
October 17, 2023 • Attribution of Results (DSM vs. IRP)
• Shareholder Incentives
• Approach to Incrementality to Base Rates and Use of IRP Deferral
Accounts
October 31, 2023 • IRP Deferral Accounts (continued discussion)
• Risk
November 28, 2023 • IRP Pilots Discussion (impact of NRCan’s announcement)
• IRP Plan – Owen Sound
• DCF+ Model
December 12, 2023 • DCF+ (continued discussion)
• IRP Shareholder Incentives – Electricity Sector Learnings
• DSM/ IRP Attribution
• AMP Update and IRP Assessment Process
• IRP Pilot Update
February 21, 2024 • Technical Evaluation Process
March 20, 2024 • 10-Year Plan Update and Next Steps for IRP Pilots
April 10, 2024 • Updates to the System Reinforcement Plan
• IRP Pilots Discussion
• IRP-Related Proposals for Phase 2 of Rebasing
April 24, 2024 • IRP Pilot Proposals
• Follow-up to Takeaways from the Last Meeting
• IRP Pilots – Draft Letter to OEB
May 10, 2024 • Economic Screening (Low Cost/ Low Value Projects)
• 2023 IRP Annual Report
• Energy Transition Adjustment Factors
June 5, 2024 • Written Feedback on Draft 1 of Enbridge’s IRP Annual Report
• Working Group Report and 2024 Priorities
• IRP Pilots – Application Update
June 19, 2024 • IRP Reports (Discussion on Enbridge’s Final IRP Annual Report
and Comments on the Working Group’s Annual Report)
• Energy Transition Adjustment Factors (continued)
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3.1. IRP Pilot Evidence
Per the IRP Framework, Enbridge Gas was expected to develop and implement two IRP pilot
projects by the end of 2022. The pilots were expected to be an effective approach for Enbridge
Gas to understand and evaluate how IRP can be implemented to avoid, delay, or reduce facility
projects. The IRP Pilot Projects application was filed by Enbridge Gas to the OEB on July 19,
2023, under EB-2022-0335.
Leading up to the filing of the Pilot application, Enbridge Gas engaged the Working Group for
multiple discussions on the development of the two pilot projects in Parry Sound and the areas
around Southern Lake Huron. Enbridge Gas sought advice on the scope of the enhanced
targeted energy efficiency (ETEE) program and demand response (DR) program, consideration
of appropriate incentive levels for ETEE, as well as the potential inclusion of limited enhanced
electric measures like cold climate air source heat pumps and ground source heat pumps. The
Working Group also considered other advanced technologies like hybrid heating, thermal
energy storage, and gas heat pumps. The Working Group also discussed the importance of
adequate data collection, contemplated the appropriate levels of encoder receive transmitters
(ERTs) and hourly metering coverage required, and inquired about Enbridge Gas’s planned
data analysis and evaluation for optimized learnings. The Working Group also provided input on
the flexibility of pilot project costs and budgets, use of a simplified DCF+ cost-benefit test (Stage
1 only), and cost recovery and allocation methodologies.
Enbridge Gas considered the Working Group’s input in the final design of its pilot proposals and
provided the Working Group with an opportunity to review and provide any feedback on its draft
evidence. It was ultimately Enbridge Gas’s decision on what Working Group feedback to
incorporate into its Pilot application. Working Group members were generally supportive of most
elements of the proposed pilot projects as described in the filed application, although a full
consensus on all aspects was not reached. In particular, several members had concerns with
the proposal to fund emerging gas technologies like gas heat pumps. Enbridge Gas’s
application noted they could make known through the regulatory approval process where a
member of the Working Group had an outstanding concern with one or more elements of the
proposed pilots.
As planning on the pilots progressed, Enbridge Gas engaged in various stakeholder activities
including the initiation of stakeholder engagements with representatives from municipalities,
local electric distribution companies, and the IESO. Enbridge Gas reached out to the pilot
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communities through in-person open house sessions to provide information on the proposed
pilot projects and to get feedback from the public. Enbridge Gas also presented the proposed
pilot projects at council meetings and obtained letters of support from the Town of Parry Sound,
the City of Sarnia, and the Town of Plympton-Wyoming. The Working Group was informed of
the details and results of Enbridge Gas’s engagement efforts after the stakeholder events had
occurred. The Working Group provided feedback on how Enbridge Gas could continue its
stakeholder efforts for greater effectiveness.
Changes to pilot application:
Enbridge Gas notified the Working Group and the OEB in a letter filed on November 10, 2023,
of Natural Resources Canada’s (NRCan) decision to halt new intake into the Greener Homes
Grant program in February 2024. This announcement impacted the design and budget of the
IRP pilot projects, which sought to leverage the Greener Homes Grant funding. The OEB issued
Procedural Order (P.O.) #3 on November 17, 2023, where the Pilot application was put in
abeyance pending Enbridge Gas’s filing of updated evidence. Enbridge Gas sought the Working
Group’s input on potential solutions/revisions to the Pilots given the impact of the loss of NRCan
funding on the pilot budgets for ETEE programming. The Working Group discussed potential
alternative approaches to include an electric heat pump component in the pilot in the absence of
NRCan incentives, such as through on-bill recovery or additional customer incentives. Enbridge
Gas ultimately decided on the latter and filed updates to its pre-filed evidence and interrogatory
responses on December 22, 2023.
On January 12, 2024, Enbridge Gas filed a letter to the OEB requesting to keep the proceeding
in abeyance to assess the impacts the OEB’s 2024 Rebasing Phase 1 decision (EB-2022-0200)
may have on the pilot application. The OEB accepted the request in a letter dated March 12,
2024, emphasizing the importance of continuing to advance IRP by avoiding further delays to
the proceeding and supporting Enbridge Gas’s plan to engage the Working Group in
subsequent communications. Accordingly, Enbridge Gas walked the Working Group through its
System Reinforcement Plan (SRP) updates and changes to its energy transition assumptions
which altered Enbridge Gas’s customer forecast, resulting in changes to Enbridge Gas’s 10-
year capital plan. The Southern Lake Huron system need was shifted outside the 10-year
period, and facility needs in Parry Sound were reduced and delayed a few years, though a
system need remained in the 10-year plan.
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Given these changes, the Working Group discussed potential revisions to the scope of the pilot
projects, considering factors like the appropriateness of the pilot locations given the change in
system needs, how to optimize value for money and maximize pilot learnings when determining
what customers to target and which programs to deploy, and the sufficiency of metering for data
collection, analysis, and learnings. Various scope changes were explored and discussed. The
Working Group was generally supportive of a revised scope for both IRP Pilot Projects that
preserved demand-side measures in the pilot, focused all demand-side programs (including
electrification and advanced technologies) on the Southern Lake Huron pilot (specifically the
City of Sarnia), and included potential implementation of localized compressed natural gas
(CNG) injection in the Parry Sound pilot.
Based on this discussion, Enbridge Gas determined that it is appropriate to move forward with
the Southern Lake Huron Pilot Project focused solely on demand-side alternatives, and with the
Parry Sound Pilot Project focused solely on the supply-side alternative. Enbridge Gas filed an
update letter with the OEB on April 30, 2024, and is expected to file its updated application to
the OEB by June 28, 2024.
On June 7, 2024, Enbridge Gas filed a letter to the OEB with a further application status update.
As a result of its May 2024 energy transition and demand forecast adjustment updates, the
underlying system need and associated baseline facility projects for Parry Sound have been
pushed out of Enbridge Gas’s 10-year capital forecast. Enbridge Gas determined it is no longer
reasonable to proceed with the Parry Sound pilot without a justifiable need for localized CNG
injection within the Parry Sound area. Enbridge Gas informed the Working Group of its plans to
withdraw the Parry Sound pilot from the proceeding and filed its updated evidence and
interrogatory responses to the OEB on June 28, 2024.
3.2. DCF+ Test and Guide
The Working Group made significant progress on providing Enbridge Gas with suggestions to
arrive at an enhanced DCF+ test. This was documented in a Report of the IRP Working Group
on the Discounted Cash Flow-Plus Test (DCF+ report) made public in May 2023. The DCF+
Report captures differing perspectives along with any items where consensus was reached.
The next step is for Enbridge Gas to use the Working Group’s DCF+ report to develop an
enhanced DCF+ test and supplemental handbook (DCF+ Guide) and file with the OEB for
approval. The DCF+ report included key information the Working Group identified as valuable
for Enbridge Gas to include in its DCF+ Guide, including a clear description of the purpose of
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each phase of the test, category of costs and benefits applicable to each phase, a definition of
each cost/benefit and corresponding guidance and/or formula on how to calculate each
cost/benefit, input assumptions including the source of numeric values, and high-level examples
showing how the DCF+ test would apply to primary IRPAs like geotargeted energy efficiency
and demand response.
Accordingly, Enbridge Gas developed a first draft of its DCF+ Guide which was provided to the
Working Group for review in fall 2023. To illustrate the concepts discussed and to facilitate and
complement the review of its draft DCF+ Guide, Enbridge Gas also provided the Working Group
with an example of how the DCF+ test would be used.
To leverage and continue the Working Group’s discussion in areas of the DCF+ report where
consensus was not reached or where further elaboration in the DCF+ guide is likely needed, the
Working Group first considered the approach taken by Enbridge Gas to address these issues in
draft 1 of its DCF+ Guide. The Working Group then identified and discussed outstanding
concerns upon the Working Group’s initial review of the draft DCF+ Guide. Working Group
members also had the opportunity to provide written feedback for Enbridge Gas’s consideration.
Enbridge Gas continues to work through the comments received in the DCF+ Guide. Through
continued discussions with the Working Group, Enbridge Gas hopes to evolve the spreadsheet
model and DCF+ Guide in parallel.
At this time, further discussions on the DCF+ test have not been scheduled. Enbridge Gas was
expected to file its enhanced DCF+ test and supplemental guide for approval with the OEB as
part of its first non-pilot IRP Plan application as per the IRP framework. This was initially
scheduled to be filed in 2024 (Owen Sound Reinforcement Project), but with the SRP updates
following the rebasing decision, the timing of the Owen Sound project has shifted out of
Enbridge Gas’s 10-year capital plan. Accordingly, the development of the IRP Plan for Owen
Sound has been put on hold. Enbridge Gas will continue to review and monitor system needs
changes, but at this time, there are no definitive timelines of when the first non-pilot IRP plan will
be filed and the enhanced DCF+ test finalized and adjudicated.
3.3. Policy Proposals for Non-Pilot IRP Plan
In anticipation of Enbridge Gas’s filing of its first non-pilot IRP plan, Enbridge Gas and the
Working Group prioritized discussion on several policy proposals. Through several meetings,
the Working Group provided its initial perspective on four key topics: DSM/IRP attribution, the
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role of shareholder incentives and performance metrics, incrementality and use of the IRP
deferral accounts, and consideration of how risk associated with traditional facility projects as
well as IRP alternatives could be considered. The Working Group’s initial input was documented
by OEB staff in a draft working paper. Following further discussion on these topics, the Working
Group intends to eventually convert the working paper into a public report, like the DCF+ report.
Policy proposal discussions with the Working Group are anticipated to continue before Enbridge
Gas files its first non-pilot IRP plan. The Working Group’s perspectives are expected to be
considered by Enbridge Gas as it contemplates and develops its IRP policy proposals.
The following paragraphs summarize some key points that came out of the initial Working
Group discussions.
DSM/IRP attribution: The working group considered three options for attribution of program
costs and savings between DSM and IRP when there is an overlap or similarity between energy
efficiency programs in the IRP Plan and Enbridge Gas’s broad-based DSM programs. The first
option is to continue the IRP pilot approach of fully funding ETEE within a pilot area from the
IRP Plan budget and attributing all ETEE results within the pilot area to IRP. The second option
is policy-driven attribution (potentially incorporating an adjustment factor) where some funding
for the ETEE programs comes from both the DSM and IRP budgets, with all peak demand
reductions attributed to IRP and all annual energy savings to DSM. The third option is split
attribution where results between IRP and DSM are split proportionally based on the amount of
funding from each budget or on a different basis that attempts to quantify the relative
importance of IRP versus DSM in influencing participant uptake. The Working Group identified
opportunities, preferences, and challenges for each option.
Shareholder incentives and performance metrics: The Working Group’s discussion on
shareholder incentives was based on several fundamental questions. First, whether incentives
for Enbridge Gas should be available for IRP and if so, how they should be structured. Second,
where incentives should be tied to performance metrics or objectives, and whether incentives
should be specific to each IRP plan, on a system-wide basis, or both. The Working Group
discussed the opportunities, risks, and challenges of the three incentive options presented in the
OEB’s Framework for Energy Innovation Report4: performance-target or scorecard-based
incentives, shared savings mechanism, and margin on distributed energy resources payments.
Considering the similarities and differences between the gas and electricity sectors, the Working
4 https://www.oeb.ca/sites/default/files/FEI-Report-20230130.pdf
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Group assessed how applicable and appropriate the Framework for Energy Innovation’s
shareholder incentives are for IRP. Likewise, the Working Group considered the OEB/
Guidehouse webinar5 on possible incentive mechanisms for DERs for the electricity sector and
their applicability to IRP.
IRP Deferral Accounts: The Working Group’s discussion on incrementality and use of the two
OEB-approved IRP deferral accounts (IRP Operating Costs Deferral Account and IRP Capital
Costs Deferral Account) considered what costs should be included in each of the deferral
accounts and how the incrementality of IRP costs relative to base rates should be addressed.
For capital costs, the Working Group discussed potential IRP activities that would be eligible for
capitalization and how to account for the revenue requirement related to avoided facility costs
as an offset (credit to ratepayers) in the capital deferral account. For operating and maintenance
costs, the Working Group discussed the eligibility of activities including costs for external studies
that may provide general learnings on IRP, as well as project-specific costs that were
undertaken as part of the IRP assessment of alternatives but did not end up being implemented
(e.g. environmental impact analysis for facility projects). Several follow-up action items and
discussion topics were identified including Enbridge Gas’s preparation of worked-out examples
of treatment of costs in various hypothetical scenarios and timings including how offsets work.
This will be revisited in future Working Group meetings.
Risk: Lastly, the Working Group discussed various types of risk/ uncertainty that are expected
to be considered in an IRP Plan and Enbridge Gas’s proposals on how these risks would be
mitigated and managed under the IRP framework. Discussions were primarily focused on
demand forecast risk/ stranded asset risk and its linkage and consideration in the DCF+ test,
potential health and safety risk associated with navigating through newer IRPA technologies,
environmental benefits of an IRPA and/or the environmental risks of the facility project, and risk
of underperformance of an IRPA. The Working Group considered where and how the risk
should be addressed quantitatively (where possible) or qualitatively. Several clarification points
and potential research takeaways were identified for Enbridge Gas to be revisited with the
Working Group at a future meeting.
5 https://www.oeb.ca/regulatory-rules-and-documents/rules-codes-and-requirements/filing-guidelines-third-party-ders
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3.4. IRP Assessment Process and Demand Forecasting
In May 2023, Enbridge Gas began discussions with the Working Group on how it assesses the
identified system needs in its AMP for their suitability for IRP. Enbridge Gas provided the
Working Group with an overview of its current process by sharing details on the process flow
and walking members through two specific project examples – one that passed, one that failed
– to demonstrate the sequence of questioning and responses to the binary screening and
technical evaluation process. The Working Group provided feedback on Enbridge Gas’s IRP
technical review template and the overall process for potential improvements.
Enbridge Gas continued to refine its IRP assessment process throughout the year, focusing on
integrating it into its asset investment planning management process (AIPM). As part of these
efforts, Enbridge Gas proposed to the Working Group to introduce an initial IRP applicability
screening that combines initial technical screening with a minimum economic threshold of $2M
before conducting a detailed technical and economic evaluation of applicable investments. By
identifying “low cost, low value” investments early in the process, Enbridge Gas believes it will
reduce non-value-added work and prioritize resources to evaluate and implement viable IRP
plans. The Working Group identified some risks and concerns in further limiting opportunities for
potential IRP projects and discussed the appropriateness of a $2M threshold. Some Working
Group members emphasized the importance of reducing or eliminating the cost threshold over
time so Enbridge Gas can develop the capability of evaluating smaller projects on a routine
basis and identifying set IRP solutions for different categories of system needs. The Working
Group also considered how the threshold aligns with other jurisdictions and existing policies.
Discussions with the Working Group on Enbridge Gas’s continued refinement and integration of
its IRP processes are anticipated to continue in 2024.
Closely related to Enbridge Gas’s IRP assessment process is the demand forecast
methodology that Enbridge Gas uses in its AMP to identify system needs. Enbridge Gas is
revising its demand forecast based on updated information in its System Reinforcement Plan
and revisiting the energy transition assumptions it originally developed as part of its rebasing
application. Enbridge Gas engaged the Working Group in early 2024 to provide an update and
seek initial feedback on its energy transition assumptions and adjustments in its forecasting
processes. Enbridge Gas is reviewing policy signals, identifying customer trends/ behaviors,
and obtaining stakeholder input to layer in its energy transition adjustments to existing and
projected customer forecasts. Enbridge Gas is also beginning to take a regional view of the
energy transition, which requires coordination with local distribution companies and the city to
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ensure projections are aligned. The Working Group provided suggestions of other sources like
major user trends, analyzing egress data, and incorporating sensitivity analysis to identify a
potential range of energy transition adjustments. Additional discussions on energy transition and
forecasting are anticipated to continue throughout 2024.
4. IRP Priorities and Working Group Activities in
2024
In June 2024, the Working Group held a preliminary discussion of subsequent priorities for the
implementation of the IRP Framework in 2024, and the role the Working Group should have.
Several members also made suggestions for 2024 priorities in their individual comments
(Chapter 2).
The Working Group considered the activities Enbridge Gas identified as its IRP priorities for
2024 in its 2023 annual IRP report:
• Stakeholder/ Municipal Outreach
• Planning/ Coordination with the Electric Sector
• Continued IRP Evaluation
• DCF+ Test
• Pilot Projects
• Policy Proposals (for Non-Pilot IRP Plans)
• System Pruning
Of Enbridge Gas’s identified 2024 priorities, one or more members of the Working Group
identified the following items as high priorities. First and foremost, multiple members would like
to expedite IRP pilot implementation to have the pilots implemented for the upcoming heating
season, so another year of data on IRP learnings is not lost. Several members expressed a
preference to restart the DCF+ discussions to finalize the DCF+ test and accompanying
handbook as soon as possible. Members are interested in discussing various aspects of the IRP
project evaluation process including dollar thresholds, timing considerations, and the rationale
for screening out projects. Several Working Group members expressed interest in making
progress in discussing and developing a system pruning/electrification pilot, although one
member noted potential concerns about conducting these activities within the purview of a rate-
regulated utility. Lastly, individual members noted: tracking and learnings from other
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jurisdictions' IRP best practices; focusing on opportunities for non-pilot IRP project
implementation to delay/avoid further facility spending, and further consideration of supply-side
alternatives, including distribution system modifications, and how these fit into the IRP
evaluation process.
OEB staff will work with Enbridge Gas to develop an updated schedule/work plan for the
Working Group based on 2024 priorities.
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Appendix F: Pilot Feedback
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Appendix G: IRP Assessment Screening and Evaluation Guidelines
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IRP Assessment
Screening and
Evaluation Guidelines
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Introduction
This document outlines the IRP Assessment Screening Criteria and rationale used in the process of determining viable IRP Plan
development and implementation. A previous version of the content in this section was filed at JT 5.36 Attachment 2 and examples
of the detailed technical evaluation form can be found at JT 5.36 Attachment 3 and 4. Appendix G is largely consistent with this
filing, with enhancements to ensure clarity.
This process will be reviewed and updated annually to reflect the latest IRP Framework requirements and changes to the energy
transition landscape (i.e., electrification and acceleration of energy transition resulting in energy demand reductions).
The IRP Evaluation Screening and Evaluation criteria described in this document are conducted using the direction and guiding
principles provided by the OEB in its IRP Decision and Order (EB-2020-0091). The investments considered as part of this binary
screening and technical evaluation process include investments within Enbridge Gas’s Asset Management Plan (“AMP”) and are
limited to regulated Enbridge Gas investments. This document will be updated on an annual basis to reflect process updates and
learnings gained through the year.
As Enbridge Gas has worked through its first IRP binary screening and technical evaluation of the investments in the AMP, certain
learnings have been identified. These learnings have led to some investments being removed either ahead of the binary screening
(this was identified as “Initial Screening”) or in the process of completing the technical evaluation (this was identified as “Initial
Technical Evaluation”). The rationale for the removal of these investments from further evaluation is outlined in this document. In
future AMP investment evaluations, Enbridge Gas will systematically apply these learnings to allow focus on the geographical areas
and investment types that are most likely to yield an IRP Plan that is both technically and economically feasible.
Process Overview
1. Initial Screening
The evaluation process began with removing non-gas-carrying asset investments from the list of 2023-2032 AMP
investments that would proceed to the binary screening phase.
2. Binary Screening
Investments are screened out as per Section 5.2 of the IRP Framework. Investments with the Asset Class of Customer
Connections will also be included in the list of Binary Screening requirements. This was reviewed with the TWG in May 2023.
3. Technical Screening & Evaluation
Investments undergo an initial technical screening to determine whether a detailed technical evaluation is required.
To evaluate whether an investment could have technically feasible IRPAs, Enbridge Gas determined which AMP investment
categories the Company considered to be driven in part, or in full, by design hour/day demand. This includes projects with
the asset class of “growth”, “distribution pipeline”, or “distribution station”. Enbridge Gas then determined the level of design
hour/day demand reduction required to meet a system need by calculating the total customer design hour/day demand for
natural gas and the total current design hour/day capacity; the difference between these two factors determined the design
hour/day demand capacity required to meet the system needs. Energy transition adjustments are taken into consideration
as part of the demand forecasting process, as noted below. Enbridge Gas then assessed the technical potential of IRPAs to
meet a system need. Where IRPAs have a technical potential to reduce the design hour/day demand reduction without
compromising the safety and reliability of the system, these investments will pass the technical evaluation.
4. Economic Evaluation
Investments that have passed technical evaluation will be evaluated economically to compare the IRPAs to the baseline
facility alternative through the Discounted Cash Flow-plus (“DCF+”) test. The DCF+ results for the IRPAs and the baseline
facility alternative will be compared to one another to determine the optimal alternative or combination of alternatives to meet
the system need. Investments that have passed the economic evaluation with an optimal alternative that is inclusive of one
or more IRPAs will be reviewed and selected for IRPA Plan Development.
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Initial Screening
Ahead of the binary screening, investments in non-gas carrying assets were removed. These investments are in the “Real Estate &
Workplace Services”, “Fleet & Equipment”, and “Technology & Information Services” asset classes.
Binary Screening
All remaining investments are subject to the binary screen criteria as provided by the OEB. Investments that satisfy the binary
screening criteria were removed from further evaluation.
Investments deemed Emergent Safety Issue
“If an identified system constraint/need is determined to require a facility project for Enbridge Gas to offer safe and reliable
service or to meet an applicable law, an IRP evaluation is not required.”43 Investments considered as emergent safety issues
would include, but is not limited to, replacing mains and services after a leak requiring immediate attention has occurred.
Investments failing based on Timing
“If an identified system constraint/need must be met in under three years, an IRP Plan could not likely be implemented and its
ability to resolve the identified system constraint could not be verified in time. Therefore, an IRP evaluation is not required.
Exceptions to this criterion could include consideration of supply side IRPAs and bridging or market-based alternatives where
such IRPAs can address a more imminent need”.44
Investments failing based on Cost ($) Threshold
“If a facility project is being advanced for replacement or relocation of a pipeline and the cost is less than the minimum project
cost that would necessitate a Leave to Construct approval, then an IRP evaluation is not required”.45 Enbridge Gas applied a
cost threshold of $2M to screen replacement or relocation projects out at this stage, as well as any associated main
replacement/relocation programmatic spend.
Customer-Specific Build
“If an identified system constraint/need has been underpinned by a specific customer’s (or group of customers’) clear request
for a facility option and either the choice to pay a Contribution in Aid of Construction or to contract for long-term firm services
delivered by such facilities, then it is not appropriate to conduct IRP analysis for those projects”.46
Community Expansion & Economic Development:
“If a facility project has been driven by government legislation or policy with related funding explicitly aimed at delivering natural
gas into communities, then an IRP evaluation is not required.”47 As noted in the AMP48, Community Expansion and Economic
Development projects are not included in the AMP and therefore their associated IRP evaluation is not captured in the AMP.
Additionally, investments with the asset class of “Customer Connections” will be screened out at the Binary Screening stage.
Customer Connection-related projects are required to serve new customers connected in accordance with guidelines of
EBO 188. The OEB concluded that as part of the first-generation IRP Framework it is not appropriate to provide funding to
Enbridge Gas for electricity IRPAs.
43 EB-2020-0091 Decision and Order, Integrated Resource Planning Proposal, July 22, 2021, p. 47 44 EB-2020-0091 Decision and Order, Integrated Resource Planning Proposal, July 22, 2021, p. 48 45 EB-2020-0091 Decision and Order, Integrated Resource Planning Proposal, July 22, 2021, p. 49 46 EB-2020-0091 Integrated Resource Planning Proposal, Decision and Order July 21, 2021, p. 44.
47 EB-2020-0091 Integrated Resource Planning Proposal, Decision and Order July 21, 2021, p. 48. 48 EB-2022-0200 Exhibit 2, Tab 6, Schedule 2, p. 282
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The investments in the customer connections asset class are related to costs associated with serving new customers,
including materials and installation of distribution mains, services and regulating equipment. Enbridge Gas determined that
implementing an IRPA could not reduce the size of the assets, as these cannot be further downsized. In addition, there are
no non-gas IRPAs available within the current IRP Framework that can be offered to avoid the customer connection
service being requested. Therefore, investments under this category should be screened out through the binary screening
phase, in advance of technical evaluations. It should be noted that any associated main reinforcement investments are still
subject to the binary screening and technical evaluation process.
Technical Screening and Evaluation
As per the OEB Decision, system needs progressing past the IRP binary screening will proceed through to a technical evaluation.
The technical screening and evaluation stage is comprised of a technical screening and technical evaluation.
Enbridge Gas has undertaken detailed technical evaluation project review of these investments, including initial verification of the
forecasted need(s), project cost(s) and project driver(s). Through this process, certain categories and investment types were
identified in which IRPAs would not be considered effective. The categories and rationale are described below and in Table 1. In the
future, these investments will be systematically screened out during the initial IRP technical evaluation process. It is expected that
through continued technical evaluations, these categories would be refined and updated to reflect any changes.
Concurrently with the technical evaluation project review process in 2023, the Enhanced Distribution Integrity Management Program
(“EDIMP”) was approved and established. As EDIMP pipelines undergo review and assessment, there may be changes to the
scope and timing of the projects currently listed in the AMP, which in turn could affect the subsequent IRP analysis. These projects
will be reviewed closely to ensure technical evaluation is completed on the updated scope.
Technical Screening
As noted above, Enbridge Gas identified categories of investments that do not have a technically feasible IRPA and were
subsequently removed from detailed technical evaluation. The categories of projects, their corresponding technical evaluation
commentary and rationale are listed below.
Customer Connections
• Technical Evaluation Comment: Customer Connection-related projects are required to serve new customers
connected in accordance with guidelines of EBO 188. The OEB concluded that as part of the first-generation IRP
Framework it is not appropriate to provide funding to Enbridge Gas for electricity IRPAs; therefore, IRPAs are not
applicable.
Due to ensuring consistency of the IRP Evaluation progress reporting, and previously reported values for a Binary
Screening “pass” or “fail,” investments with the asset class of “Customer Connections” that passed Binary Screening and
failed at the Technical Screening and Evaluation stage will keep it’s originally filed statuses for the 2023-2032 AMP.
Changes to the screening process as a result of the learnings will be reflected in the 2025-2034 AMP.
Compressor Stations
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• Technical Evaluation Comment: Compression Station related projects are required to maintain existing
deliverability and throughput. This is necessary to maintain security of supply and stable natural gas pricing
during supply disruptions.
The investments in the compression stations asset class related to the maintenance of the existing fleet of compressors
include the periodic original equipment manufacturer (“OEM”) prescribed overhauls and replacement of components that
are not performing as intended or are obsolete. These types of investments cannot be offset by IRPAs and therefore will
be screened out during technical evaluation. However, any investments driven by growth would be subject to the detailed
technical evaluation process.
Hydrogen Blending
• Technical Evaluation Comment: Hydrogen related projects are required as no IRPAs can replace the hydrogen
feasibility assessments and hydrogen blending initiatives.
The investments in the hydrogen blending asset class/program are related to the use of hydrogen in the distribution
system, studies on hydrogen blending and are focused on reducing the carbon footprint of the existing transmission and
distribution system. These investments cannot be offset by IRPAs and therefore will be screened out during technical
evaluation.
Storage Pools & Wells
• Technical Evaluation Comment: “Storage Pools & Well related projects are required to maintain existing
deliverability and throughput. This is necessary to maintain security of supply and stable natural gas pricing during
supply disruptions.”
The investments in the storage pools and wells asset class are related to maintenance and compliance driven upgrades to
allow for ongoing deliverability from the storage pools. This includes the drilling of observation wells for compliance
reasons and work that arises annually from the Integrity Management Program. These investments cannot be offset by
IRPAs and therefore will be screened out during technical evaluation.
Distribution Stations
• Technical Evaluation Comment: Distribution Station condition related, IRPAs not applicable
The investments in this category are related to distribution station projects driven by the condition and not by growth.
These distribution station condition related projects are prioritized based on inspections that evaluate the condition of
various components (regulators, valves, piping, etc.) and systems (heating, odourant, communications, etc.) at the
stations. In some instances, the specific projects are time constrained and low in dollar value and would fail at the binary
screening stage. For larger projects, an understanding of the impact on upstream and downstream facilities is required and
“like for like” replacement is usually preferable – particularly if a full station replacement is not being planned. As such, all
condition related station rebuilds, and replacements will be screened out during technical evaluation. However, any station
investments that involve an element of growth would be subject to the detailed technical evaluation process.
CNG Facilities
• Technical Evaluation Comment: See investment description – IRPAs not applicable for CNG
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These investments are related to the ongoing replacement and upgrade of CNG facilities to fuel Enbridge Gas’s natural
gas vehicles. These needs cannot be replaced through IRPAs, and therefore will be screened out during the technical
evaluation.
Other
• Technical Evaluation Comment: See investment description, IRPAs not applicable
The investments in this category were determined that there would not be a technically feasible IRPA and are described
below in Table 1. Where applicable, there are notes as to how these will be systematically removed prior to IRP Technical
Evaluation in future.
Project Status/ Timing Related
Technical Evaluation Comments:
• A Leave to construct regulatory process has received OEB decision for approval of proposed project scope.
• LTC regulatory process in progress
• N/A - Project in construction phase
• N/A - Investment Cancelled
• N/A - Project Completed
Investments that fall within this category are those that are already under construction, already granted leave to construct
by the OEB or are projects that have been cancelled. These investments will be screened out during technical evaluation.
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Table 1 – Description of Investments Screened out of the Technical Evaluation Project Review
Sub-category Asset Class Asset
Program
Description
1 AMI Pilot Utilization UTIL-
Monitoring
Systems
The AMI Pilot will establish the technical and economic benefits related to the installation of AMI meters
and associated infrastructure. No technically feasible IRPA’s can replace this spend and the investment
will be removed from further Technical Evaluation.
2 AMP Fitting Distribution Pipe DP-Service
Relay
An AMP fitting is a mechanical fitting installed between 1969 and 1984, on below ground residential gas
service lines, to transition from a plastic service line to a copper riser. Locations with an AMP Fitting are
identified annually and prioritized based on risk. As such the investments should be excluded based on
timing and the fact that individual service replacements cannot be offset by IRPA’s.
3 Class Location Distribution Pipe &
Transmission Pipe
& Underground
Storage
DP-Class
Location
TPUS-Class
Location
This is one of the Integrity Management Programs in which the spend is held in a Programmatic spend
budget to cover specific projects that are identified each year. Class locations projects arise when a
facility needs to be relocated because of increased development and associated population density
around the facility. Going forward this programmatic spend budget will be removed from IRP Technical
Evaluation, but any specific pipeline replacements will be included for IRP Evaluation
4 Compression
Stations
Compression
Stations
All See section above on Compression Stations
5 Corrosion Distribution Pipe DP-Corrosion This programmatic spend covers the replacement of depleted anodes, work arising from bridge crossing
inspections, and repairs to rectifier beds. Once found, these problems must be addressed quickly to
avoid degradation of the pipe and, as such, will be removed from IRP Evaluation based on timing.
6 Depth of Cover
Program
Transmission Pipe
& Underground
Storage
TPUS-Integrity This programmatic spend budget is for facilities that are identified each year as exposed or shallow
leading to an increased risk of 3rd party damage. Once identified the pipeline must be lowered,
replaced, or otherwise protected to control risk. Going forward this programmatic budget spend will be
excluded from IRP Technical Evaluation, but any resultant pipeline replacements be included for IRP
Evaluation.
7 District Station Distribution
Stations
DS-Station
Rebuilds & B &
C Stations
These investments hold budget for specific station rebuild investments that have been identified through
annual inspections and that have been prioritized for rebuild based on condition.
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8 Farm Taps Utilization UTIL-
Regulator Refit
This is programmatic spend that is budgeted to cover the costs of remediating situations in which there
are problems with the first or second cut of the regulation at a customer’s premise. These are repaired
as they are found and should be eliminated based on timing.
9 Facilities
Integrity
Management
Program
(FIMP)
Distribution
Stations
DS-Integrity This is programmatic spend that is budgeted to cover the costs of large station inspections that must be
completed annually to scope the extent of work that is required at each large station investment
identified in the AMP. Going forward, all such Station programmatic spend that is driven by condition,
end-of-life, and compliance will be removed from IRP Technical Evaluation.
10 Fire
Suppression
Distribution
Stations
DS-Gate,
Feeder & A
Stations
These investments relate to the installation of Fire Suppression at Distribution Stations with Odourant.
Going forward all such Station programs that are driven by condition, end-of-life, and compliance will be
removed from IRP Technical Evaluation.
11 Geohazard Distribution Pipe DP-Integrity This integrity management programmatic spend is budgeted to cover the costs related to identifying
pipelines that must be replaced because of risks related to geohazards. This spend will be excluded
from IRP Technical Evaluation going forward but any resultant replacement projects will be included in
IRP Technical Evaluation.
12 Independent
Asset Integrity
Review (IAIR)
Distribution Pipe &
Transmission Pipe
& Underground
Storage
DP-Integrity,
TPUS-Integrity
This is programmatic spend that is budgeted for work that results from the Independent Asset Integrity
Review. Although the programmatic spend budgeted here cannot be assessed for IRP Alternatives, any
resultant pipeline replacements will be included in the IRP Technical Evaluation.
13 Integrity Digs Distribution Pipe &
Transmission Pipe
& Underground
Storage
DP-Integrity,
TPUS-Integrity
This programmatic spend is budgeted to cover the costs related to repairs and replacements that are
identified through in-line inspections. This programmatic budgeted spend will be excluded from future
IRP Technical Evaluation but pipeline replacement projects found as a result of the integrity dig work will
be included in the IRP Evaluation.
14 Integrity
Retrofit
Distribution Pipe,
Distribution
Stations &
Transmission Pipe
& Underground
Storage
DP-Integrity,
DS-Integrity,
TPUS-Integrity
This is programmatic spend that is budgeted for installing pig launchers and receivers, allowing annual
in-line inspection to be accomplished more easily and the life of transmission pipelines to be potentially
extended. This work takes place at stations and does not affect the distribution system itself. No
technically feasible IRPA’s exist for this type of work, and it will be removed from the Technical
Evaluation going forward.
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15 Inside Room
Regulators
(IRR)
Distribution
Stations
DS-Inside
Regulator &
ERR Program
This is programmatic spend that is budgeted for remediation of inside regulation sets based on risk.
There is no technically feasible IRPA that could address this need and they will be removed from the
Technical Evaluation going forward.
16 Large stations Distribution
Stations
DS-Gate,
Feeder & A
Stations
These stations are identified through inspections and prioritized for rebuild based on condition. Each
year, this programmatic spend is converted into specific projects. Any identified investments for which
growth plays a role will be included in the IRP Evaluation. It should be noted that there is also the
possibility that reduced load will drive some investment in stations.
17 Liquified
Natural Gas
(LNG)
LNG All These investments relate to the maintenance of the Hagar LNG facility that is used to peak shave the
load in the Sudbury area. Unless driven by Growth, all investments at the Hagar facility will be excluded
from the Technical Evaluation moving forward.
18 Low Pressure
Delivery Meter
Sets (LPDMS)
Utilization UTIL-
Remediation
This is programmatic spend budgeted to cover the inspection and remediation of Low-Pressure Delivery
Meter sets, which are usually at commercial customer locations. Similar investments were excluded at
binary screening based on the dollar threshold. Going forward, these investments will be removed from
the Technical Evaluation.
19 Main & Service
Repl - Leaking
Distribution Pipe DP-Service
Relay
Similar investments in the EGD Rate Zone were excluded at Binary Screening and going forward these
too will be excluded at Binary Screening as Emergent Safety Issue. Aside from the safety concern,
leaks must be addressed quickly to avoid GHG’s.
20 Meter
exchanges
Utilization UTIL-
Regulator Refit
This programmatic spend is budgeted to cover the costs of replacing meters through the Measurement
Canada approved processes.
21 Maximum
Operating
Pressure
(MOP)
Verification
Distribution Pipe &
Transmission Pipe
& Underground
Storage
DP-
Replacements,
TPUS-
Replacements
This programmatic spend is budgeted to cover the replacement of pipelines where this may be required
because of a review of records for pipeline systems operating above 30 per cent SMYS. Once the MOP
has been identified and based on the associated risk, the pressure in these pipelines may need to be
reduced until the pipeline can be replaced. The programmatic budgeted spend will be removed from
Technical Evaluation going forward but specific pipeline replacement projects will be included in IRP
Evaluation when they are identified.
22 Odourant
Program
Distribution
Stations
DS-Gate,
Feeder & A
Stations
These investments are for the upgrade of odourant systems at stations. Similar investments failed at
binary screening because of timing and because of the dollar threshold. Going forward all such Station
programs that are driven by condition, end-of-life, and compliance will be removed from IRP Technical
Evaluation.
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23 Pressure
Factoring
Metering
(PFM)
Program
Stations DS-Station
Rebuilds & B
and C Stations
This programmatic spend is budgeted to cover the costs of PFM stations that require a bypass. There is
no technically feasible IRPA to address this need and this programmatic budgeted spend will be
removed from Technical Evaluation moving forward.
24 Re-class to
CNG
Distribution
Stations
DS-CNG One investment relates to CNG and should have been allocated to the “See investment description –
IRPA not applicable for CNG investments”.
25 Relocation
Program
Distribution Pipe DP-
Relocations
This programmatic spend has been budgeted to cover the costs of projects that are identified annually
in response to the requirements of municipalities and other agencies. This programmatic budgeted
spend will be removed from Technical Evaluation moving forward but specific pipeline replacement
projects will be included in IRP Evaluation.
26 Remote
Terminal Units
(RTU)
Distribution
Stations
DS-Gate,
Feeder & A
Stations
These investments are for the replacement of Remote Terminal Units that are no longer supported by
the manufacturer. Similar investments were eliminated at Binary Screening because of Timing. Going
forward all such Station programs that are driven by condition, end-of-life, and compliance will be
removed from IRP Technical Evaluation.
27 Storage
Facility
Transmission Pipe
& Underground
Storage
TPUS-
Improvements
As noted above, investments related to Storage Pools and Wells will be excluded from Technical
Evaluation going forward unless they are driven by growth.
28 Telemetry Distribution
Stations
DS-Gate,
Feeder & A
Stations
These investments are for telemetry at distribution stations. Similar investments failed at binary
screening because of the dollar threshold. Going forward all such Station programs that are driven by
condition, end-of-life, and compliance will be eliminated from IRP Technical Evaluation.
29 Vintage Steel
Main (VSM)
Distribution Pipe DP-
Replacement
There is a programmatic spend budgeted for Vintage Steel Main projects that have not yet been
identified. Although this programmatic spend will not- be put through Technical Evaluation projects,
once identified, will go through IRP Evaluation.
30 Well Laterals Transmission Pipe
& Underground
Storage
TPUS-Integrity As noted above, investments in Storage Pools & Wells, and their associated Integrity Management
Programs will be similarly excluded from Technical Evaluation.
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Technical Evaluation
Investments that are not screened out through the technical evaluation screening, as noted above, proceed to a technical
evaluation. Examples of the technical evaluation form can be found at EB-2022-0200, JT 5.36 Attachment 3 and 4.
The following are the types of technical evaluation commentary associated with investments with technically feasible IRPAs.
IRPA(s) applicable – IRPA(s) applicable could defer, reduce or eliminate project scope
These investments pass the technical evaluation as there are technically feasible supply or demand side IRPA(s) that
could impact the project scope. These investments proceed with detailed system modelling for peak hour demands.
The following are the types of technical evaluation commentary associated with investments with no technical feasible IRPAs.
These investments will be excluded from further detailed technical evaluation.
Scope is NPS 2, cannot downsize further or retire
The existing scope is already NPS 2 and thus cannot be further downsized. These investments were then reviewed to
determine whether they could be retired. These scopes had services coming off the pipe that needed to be maintained and
thus cannot be retired. Since the pipe size cannot be reduced beyond NPS 2 and cannot be eliminated, IRP has no impact
to the project scope, and therefore fails technical evaluation.
Potential to be downsized to NPS 2. Further assessment closer to ISD
During technical evaluation, it was determined that the project scope could potentially be replaced with NPS 2 prior to any
IRP assessment. If the pipe size can be reduced, then IRP will not be applicable; the scope will be confirmed when the
project enters the detailed design phase.
Potential to be downsized to NPS 2, but need to avoid bottlenecks and maintain system resiliency
A portion of the project scope could potentially be replaced with NPS 2 prior to any IRP assessment. It is recommended
that pipe size is maintained for segments of trunk main and for system resiliency. Thus, IRP is not applicable to the project
scope; the scope will be confirmed when the project enters the detailed design phase. These projects may benefit from
having a broader assessment of the needs in the area and the potential for reductions via a geographically focused IRP
Plan. This type of analysis was beyond the capacity of the team for this first pass through the IRP Technical Evaluation
process but is an area that will be explored in the future.
ETEE could reduce pipe size, but it is a trunk main
There are investments for which ETEE could potentially reduce the pipe size, but in doing so, would introduce a bottleneck
in a trunk main which is not desirable from a network operations perspective.
Timing – Market Based Supply Side not available
Some investments failed because they are required in the near term (1-3 years) and there is no technically feasible supply-
side alternative that can meet the need.
Updated: 2024-07-02, EB-2024-0125, Exhibit H, Tab 1, Schedule 1, Page 97 of 97
Page 599
Indigenous Working Group Report
May 31,2024
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Table of Contents
1 Introduction…………………………………………………………………………………. 3
2. Indigenous Working Group Matters……………………………………………………… 3
3. Indigenous Working Group Meetings & Minutes………………………………………. 3
4. Summary of Discussions………………………………………………………………….. 3
5. Summary of Presentations to the Group………………………………………………... 4
6. Indigenous Working Group Capacity Funding………………………………………….. 5
7. Indigenous Working Group Capacity Funding for 2025……………………………….. 6
Appendix A - Enbridge Gas Inc. Indigenous Working Group Meeting Minutes
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1. Introduction
As set out in the complete settlement on item 4 of the Settlement Proposal and
accepted by the Ontario Energy Board (OEB) in its Decision on Settlement Proposal in
Phase 1 of EB-2022-0200 (2024 Rebasing proceeding), Enbridge Gas Inc. (Enbridge
Gas) established an Indigenous Working Group (IWG) and has undertaken a number of
activities in relation to the IWG1. One of the required activities is for Enbridge Gas to
work with the members of the IWG to draft an annual report (IWG Report) summarizing
the activities of the IWG and initiatives planned or implemented, including minutes of the
IWG meetings. This IWG Report is to be filed as part of Enbridge Gas’s annual deferral
and variance account (DVA) proceeding. This is the first annual IWG Report.
2. IWG Members
The IWG initially consisted of Ginoogaming First Nation (GFN) and the Three Fires
Group (TFG), which groups were intervenors in the Rebasing proceeding. The
Settlement Proposal allows for any other First Nation community or reserve to join the
IWG provided they or their distribution companies are Enbridge Gas customers.
Additional communities that have joined the IWG are Mississaugas of Scugog Island
First Nation, Chippewas of the Thames First Nation, Six Nations Natural Gas, and Kettle
and Stony Point First Nation (together with GFN and TFG, referred to as the Indigenous
Parties).
3. IWG Meetings & Minutes
The IWG has met on a number of occasions commencing with the first meeting on
September 18, 2023 (virtual) followed by the following dates (in-person and virtual)
1. September 18, 2023 virtual
2. October 17, 2023 in-person
3. December 14, 2023 in-person
4. April 30, 2024 in-person
Please refer to Appendix A to this Report for copies of the approved minutes of each
meeting.
4. Summary of Discussions
The meetings are managed in accordance with a collaborative approach of determining
agenda items and taking turns chairing. Enbridge Gas representatives have attended
meetings and provided presentations, providing information and agenda requests from
IWG members. Overall, the group looks for opportunities to expand on the discussions
1 EB-2022-0200, Decision on Settlement Proposal, August 17, 2023, Schedule A, pg. 16-20.
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Page | 4
to provide more information for the OEB and others. Discussions at meetings have
included the priorities identified by the OEB, however, the Indigenous Parties identified
a complementary list of priorities, which the IWG has begun addressing. The priorities
as identified by the Indigenous Parties are as follows and are included in the minutes
from the October 17, 2023 meeting:
Energy Transition Programs
o Heat pump pilots
o Energy efficiency pilots
o Geothermal heating pilots
Access to Natural Gas Act
Economic Partnerships
Renewable Natural Gas
Resilience and Adaptation
o Stranded assets, cleanup costs, other risks arising from potentially
declining customer base
o Ability of First Nations to transition to alternative sources of energy
Two initiatives have emerged from the IWG meetings held thus far. The first initiative
has an IWG member with interest in the topic working with Enbridge Gas on fugitive
emissions. The second is a pilot on-reserve Home Winterization program. Progress on
these initiatives will be provided in subsequent IWG Reports.
5. Summary of Presentations to the Group
Meetings include presentations from IWG members and Enbridge Gas subject matter
specialists to facilitate informed discussion of a topic. The IWG has received the
following presentations and resources:
Letter from Resilient LLP, on behalf of TFG and GFN to the IWG, which set out
guiding principles of importance for present First Nations Members of the IWG.
Presented to the IWG for its first meeting on September 18, 2023.
Summary Table of Issues, created and circulated by Resilient LLP, which
identified the topics that GFN and TFG would like to see discussed at earlier
stages of the IWG meetings, and where external experts may be needed.
Circulated and discussed for the October 17, 2023, meeting.
Overview of Enbridge Gas Inc., led by Enbridge Gas, gave a short introduction
and overview of the Enbridge Gas system. Presented to the IWG October 17,
2023.
Energy Transition Planning at Enbridge Gas, led by Enbridge Gas Manager of
Carbon & Energy Transition Planning. The presentation discussed the Pathways
Studies to determine the best way forward to GHG net zero and a low carbon
future. Presented to the IWG October 17, 2023, at the request of Indigenous
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 4 of 28
Page 603
Page | 5
Parties. A follow up presentation was given on December 14, 2023, with a focus
on the Clean Home Heating Initiative and IWG input for the Pilot Program.
Demand Side Management Pilots and Programs, led by Enbridge Gas Manager
of Energy Conservation Strategy & Policy alongside Senior Advisor of Indigenous
Energy Conservation. The presentation discussed both government and
Enbridge Gas initiatives for customers and Indigenous Communities such as the
Clean Home Heating Initiative, the Greener Homes Grant, and the Enbridge Gas
Home Winterization Program. Presented to the IWG October 17, 2023, at the
request of TFG.
Fugitive Emissions Presentation, led by Enbridge Gas Manager of Carbon
Strategy, which included an overview of GHG emission sources, reduction and
targets, with an introduction to the Federal Methane Regulations, current
emissions reductions, and the Fugitive Emissions Measurement Plan. Presented
to the IWG December 14, 2023, at the request of TFG. A follow up presentation
on the progress of the Enbridge study into the measurement plan was presented
to the IWG on April 30, 2024, at the request of Don Richards and Minogi Corp.
Access to Natural Gas Act, presentation given by Don Richardson of the TFG
recommending that the Natural Gas Expansion Program be adapted so that it is
heat technology agnostic and competitive to allow First Nation Community
access to low-carbon solutions. Suggestions of pooling funds or utilizing rate
payer funds for energy transition. Presented to the IWG December 14, 2023.
Federal Greener Homes Program Update, presented by Enbridge Gas Manager
of Residential Energy Conservation, which discussed updates and status of the
program, and how the changes will affect Enbridge Gas’ offerings and role as a
gas service provider. Presented to the IWG April 30, 2024, at the request of Don
Richardson and Minogi Corp.
Supply Chain Management (SCM) – Indigenous Engagement, presented by
Richard Brant, Supply Chain Analyst – Indigenous Engagement, on Enbridge
Gas procurement policy, reporting and target setting in SCM. Presented to the
IWG April 30, 2024, at the request of TFG.
Indigenous Employment Practices, presented by Enbridge Inc. Senior strategist
on Indigenous Collaboration and Enbridge Inc. Indigenous Recruitment Advisor.
Presentation provided an update on the employment practices and opportunities
at Enbridge corporate and outlined resources available to Indigenous employees
across the entire company. Presented to the IWG April 30, 2024, at the request
of TFG.
6. IWG Capacity Funding
Under the Settlement Proposal, Enbridge Gas was required to provide capacity funding
for the reasonable costs of each of the Indigenous Parties for their preparation for and
participation in the IWG meetings, including reasonable technical expert and legal
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 5 of 28
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assistance. The estimated budget for capacity funding to the end of 2024 was
$640,000, consisting of:
i. $240,000 for legal support;
ii. $150,000 for general consultants; and
iii. $250,000 for expert analysis and support.
To date, Enbridge Gas has received invoices from Woodward & Co, representing GFN
and Resilient LLP, representing TFG, in the amount of $43,453.57, of which $42,694.57
has been fully paid by Enbridge Gas.
The IWG is presenting the 2025 estimated budget for review by the OEB as part of the
DVA proceeding. The Indigenous Parties propose the following budget for capacity
funding for 2025.
7. IWG Capacity Funding for 2025
The Indigenous Parties presented an estimated budget for capacity funding for the
calendar year 2025 of $800,000, described as follows:
1. There is a reasonable likelihood that First Nation membership of the IWG will
continue to increase, which would mean increased representation and/or
coordination costs.
2. There is an expectation that 2025 will likely see an increased need for expert
assistance.
3. There is a growing need to reflect the changing composition of representatives
attending and supporting the IWG by amending the previous category of
“consultants” to include First Nation representatives who are not consultants.
4. Finally, the costs of the IWG over its first several months of operation are likely
not representative of the reasonable costs that will be necessary to participate in
and support the IWG in the future, since the IWG’s first few months in many ways
were a ramp-up period.
i. $265,000 for legal support;
ii. $225,000 for consultants and First Nation representatives; and
iii. $310,000 for experts.
Enbridge Gas will pay the Capacity Funding in accordance with the Settlement
Proposal, based on actual reasonable costs incurred and appropriately invoiced by the
Indigenous Parties to participate in the IWG.
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 6 of 28
Page 605
Enbridge Gas Inc. Indigenous Working Group Minutes - Draft
Minutes of a meeting of the Indigenous Work Group (IWG) held on September 17,2023.
PRESENT
Don Richardson Three Fires Group
Emily Ferguson Three Fires Group
Nick Daube Resilient LLP
Kate Kempton Woodward and Company
Caolan Lemke Woodward and Company
Jordan George Kettle and Stony Point First Nation
Catherine Pennington Enbridge Gas Inc.
Diana Audino Enbridge Gas Inc.
Lauren Whitwham Enbridge Gas Inc.
ABSENT WITH REGRETS
Chief Sheri Taylor Ginoogaming First Nation
Daniel Vollmer Resilient LLP
Lisa Demarco Resilient LLP
1.DISCUSSION ITEMS
Logistics:
•Meetings of the IWG should be hybrid (in person but with a virtual option) to ensure inclusion and
accessibility. It was recommended that strong audio/visuals be used to greater facilitate virtual
participation.
•Suggest the IWG have a rotating or co-facilitator for future meetings.
Attendees:
•Suggest the IWG establish an agenda and priorities and then engage other Communities who might be
interested.
•Animbiigoo Zaagi'igan Anishinaabek First Nation has expressed interest in participating. They are mainly
off reserve community living with natural gas in Geraldton area.
•Six Nations Natural Gas has also expressed interest in the working group.
Indigenous Working Group Report May 31, 2024 Appendix A Page 1 of 22
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•Suggest potential category for those who are seeking natural gas on reserve through Ontario Grant
program such as Aroland First Nation.
•Enbridge Gas Inc. currently services 20 First Nation communities directly. There is some distribution to
certain areas of Mississaugas of the Credit First Nation and Six Nations of the Grand River as well.
•Need to be mindful of the budget for the IWG.
Focus Areas:
•Reviewed the OEB settlement agreement for focus areas.
•Reviewed the letter provided to Enbridge Gas Inc. from Resilient LLP (Letter). Input into the Letter was
provided by other parties to the IWG; the Letter sets out guiding principles of importance for the current
First Nation members of the IWG. (For ease of reference, the Letter is attached to these Minutes)
•Discussed spending the October meeting working through the concerns addressed in the Letter and what
the IWG wants to achieve, mapping the course out for future meetings.
•Key categories for next meeting and beyond:
o Energy Transition – birds eye view scenario
o Pilots and efficiencies
o RNG Development – Sourcing and how Enbridge Gas Inc. will achieve supply
•Ontario Home Heating Initiative with Ontario government offers pilot projects for municipalities. Would
like to explore options for Indigenous Nations to have equipment.
•Recommendation to minimize use of acronyms and explain common terminology to ensure everyone
understands and can participate in the discussion.
2.NEXT MEETING
Next meeting will be held on Tuesday October 17 at the Enbridge Gas Inc. office at 500 Consumers Road North
York, Ontario M2J 1P8. We will begin at 8:30 and lunch and refreshments will be provided throughout the day.
Indigenous Working Group Report May 31, 2024 Appendix A Page 2 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 8 of 28
Page 607
APPENDIX A – LETTER TO ENBRIDGE GAS FROM RESILIENT LLP
CICULATED PRIOR TO IWG MEETING ON SEPTEMBER 14, 2023
August 23, 2023
Enbridge Gas Inc. 109 Consumers Road West London, ON N6J 1X7 Attention: Lauren Whitwam Dear Ms. Whitwam,
Re: Agenda for Initial Meetings of Indigenous Working Group We write on behalf of Three Fires Group (“TFG”) and Ginoogaming First Nation (“GFN”) (collectively, the “Indigenous Parties”) concerning the initial meetings of the Indigenous Working Group (the “IWG”), which the Ontario Energy Board (the "Board") approved on August
17 2023 as part of the larger settlement proposal (“Settlement Agreement”) in the context of Enbridge Gas Inc.’s (“EGI”) rate application. The Indigenous Parties are optimistic that the IWG will serve as an effective discussion forum for matters relating to EGI’s rates and services, as well as the impact of those rates and services on First Nations. They are similarly eager to see the first meetings of the IWG proceed in September 2023, as anticipated in the Settlement Agreement.
Accordingly, the Indigenous Parties wish to identify a set of initial discussion topics, which they propose should form the primary focus of the IWG’s initial meeting(s) in accordance with the range of issues set out in the Settlement Agreement. The Indigenous Parties have identified these topics as priorities on the basis of the significance of their impact to the relevant communities and, in the case of energy transition, with the rationale that certain topics will almost certainly require discussion at many if not all of the IWG’s future meetings, such that early agreement relating to how those discussions should develop will be essential to increasing the likelihood of a focused process and constructive outcomes.
The specific topics that the Indigenous Parties identify as priorities and wish to discuss at the initial meetings of the IWG are:
1. Energy transition programs.1 In particular, the Indigenous Parties would like to
prioritize the discussion of energy transition programs and the possibility of pilot programs relating to reliability and resilience including, but not limited to, heat pumps, geothermal heating, and energy efficiency.
2. Opportunities for economic partnership in the context of energy transition.2 The Indigenous Parties propose that the potential for partnership relating to renewable
natural gas receive early attention in the IWG.
1 Article 5 of Settlement Agreement’s “Focus Areas”. 2 Article 5 of Settlement Agreement’s “Focus Areas”.
Lisa (Elisabeth) DeMarco • Bay Adelaide Centre • 333 Bay Street, Suite 625 Toronto, ON M5H 2R2 • +1.647.991.1190 • lisa@resilientllp.com
Indigenous Working Group Report May 31, 2024 Appendix A Page 3 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 9 of 28
Page 608
3. Resilience and adaptation with impact on energy transition for First Nations.3 The Settlement Agreement identified such items within this broad category as the risk of stranded assets, clean-up costs, risks arising from a potentially declining customer base, and the ability of First Nations to transition to alternative energy sources. We also view nature-based fire prevention and response to be an integral part of this initiative. The Indigenous Parties recognize the urgent need for preventative actions and there are also larger and more comprehensive issues that may require discussion over the life of the IWG, with input from EGI and outside experts. The Indigenous Parties therefore believe that this general category must receive early attention so that members of the IWG can
agree on a path forward that increases the likelihood of focused discussions and constructive outcomes. 4. The future of the IWG.4 The Settlement Agreement identified the objective of establishing a permanent Indigenous roundtable to provide ongoing engagement with Enbridge Gas on rates and energy transition. The Indigenous Parties are optimistic that a successful IWG could serve as a model for constructive discussions elsewhere in the energy sector and beyond. They would like to ensure that the IWG gives regular and consistent thought on how these objectives are best pursued.
5. Energy transition matters of specific interest to Indigenous Parties.5 Two items under this heading that the Indigenous Parties would like to discuss in the early
meetings of the IWG are: a. the decarbonization of EGI’s gas storage operations, including the use of electric compressors instead of gas compressors; and b. EGI’s current analysis and proposed action plan for addressing fugitive emissions across pipelines, compressor stations, and other point sources.
The Indigenous Parties recognize that the Settlement Agreement assigns responsibility for convening the IWG to EGI. The Indigenous Parties will therefore expect to hear from EGI shortly on this proposed agenda and the meeting logistics, recognizing that the target date of
September is only weeks away. In the meantime, the Indigenous Parties are available to discuss the matters raised in this letter at your convenience.
3 Article 5 of Settlement Agreement’s “Focus Areas”.
4 Article 1 of Settlement Agreement’s “Focus Areas”. 5 Article 5 of Settlement Agreement’s “Focus Areas”.
Indigenous Working Group Report May 31, 2024 Appendix A Page 4 of 22
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Page 609
We look forward to hearing from you.
Sincerely,
Lisa (Elisabeth) DeMarco
c.Don RichardsonEmily FergusonKate Kempton
Diana AudinoCatherine PenningtonTania PersadNicholas DaubeDaniel Vollmer
Indigenous Working Group Report May 31, 2024 Appendix A Page 5 of 22
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Page 610
Enbridge Gas Inc. Indigenous Working Group Minutes - Draft
Minutes of a meeting of the Indigenous Work Group (IWG) held on October 17,2023 at 9:00 a.m. EST at
Enbridge Gas Inc., 500 Consumers Road, North York, Ontario M2J 1P8.
PRESENT
Don Richardson (in-person) Three Fires Group
Emily Ferguson (virtual
Nick Daube (in-person)
Three Fires Group
Resilient LLP, Three Fires Group
John Glover (virtual) Minodahmun Development LP
Andrew Bubar (virtual) Tamarack Environmental Associates
Kate Kempton (in-person) Woodward and Company, Ginoogaming First Nation
Jordan George (virtual) Kettle and Stony Point First Nation
Tracy Skye (in-person) Six Nations Natural Gas
Catherine Pennington (in-person) Enbridge Gas Inc.
Diana Audino (in-person) Enbridge Gas Inc.
Lauren Whitwham (in-person)
Sarah Taylor (virtual)
Enbridge Gas Inc.
Enbridge Gas Inc.
Sarah Crowell (virtual) Enbridge Gas Inc.
Brent Bullough (in-person) Enbridge Gas Inc.
Tania Persad (in-person) Enbridge Gas Inc.
Henry Ren (in-person) Enbridge Gas Inc.
Jennifer Murphy (in-person)
Keith Boulton (in-person)
Enbridge Gas Inc.
Enbridge Gas Inc.
Craig Fernandes (in-person) Enbridge Gas Inc.
Tausha Esquega (in-person) Enbridge Gas Inc.
ABSENT WITH REGRETS
Chief Sheri Taylor Ginoogaming First Nation
Daniel Vollmer Resilient LLP
Lisa Demarco
Caolan Lemke
Resilient LLP
Woodward and Company
1. DISCUSSION ITEMS
Review of Agenda (attached at Appendix A) and Logistics
• Lauren Whitwham presented a Safety Moment on Fall Safety and provided a safety orientation of the
meeting location
• IWG confirmed that meetings should continue to be hybrid (in person but with a virtual option) to ensure
inclusion and accessibility.
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Page 611
•Decided to rotate facilitator/chair of each IWG meeting. Nick Daube agreed to chair/facilitate the next
IWG meeting.
•The meeting minutes from September 18th were discussed, reviewed and approved. Future meeting
minutes will include the Action items arising from the meeting.
Overview of discussions and Review of Summary Table of issues circulated by Nick Daube prior to the IWG meeting
(attached at Appendix B).
•Ginoogaming First Nation and Three Fires Group advised that they had started to identify the items/topics
they would like to see discussed at earlier stages of IWG meetings.
•IWG discussed the order of priority for topics to be discussed at the IWG while recognizing each item is
important.
•Consensus that there is an Indigenous perspective within each item.
•Identified areas where experts may be required and what the scope is for those experts.
•Heat pump programs - may need more information from the Crown including Indigenous Services Canada,
Ministry of Energy and Natural Resources Canada (NRCan), and Government of Ontario to determine why
certain government programs are not available on reserve.
•Recommendation to minimize the amount that Enbridge Gas Inc. is talking at/presenting to the group
with a balance between providing necessary information with the input of independent experts.
•Consider providing information to IWG participants for review in advance of IWG meetings so members
can be ready to discuss matters.
Discussion Topics for IWG in order of priority for First Nations Participants
1.Heat Pumps
2.Stranded Assets, clean-up costs, and other risks arising from potentially declining customer base.
3.Renewable Natural gas economic partnership
4.Access to Natural Gas Act (not the Natural Gas Expansion Act, which had been inadvertently referenced in
the Summary Table of issues circulated by Nick Daube)
5.Energy efficiency pilots and geothermal heating pilots
6.Fugitive emissions – Analysis and action plan for addressing fugitive emissions
7.Nature based fire prevention and response
8.Decarbonization
9.Need for benefits of and costs of energy transition
10.Future of IWG
Areas Requiring third party Experts
1.Stranded assets/Clean-up costs (energy transition)
2.Renewable Natural Gas (RNG) economic partnership
3.Fugitive Emissions
4.Need for, benefits of, and costs of energy transition
•Kate Kempton suggested John Burrows attend an IWG meeting to speak on Indigenous Law from the
Anishinaabe perspective.
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Page 612
• Jennifer Murphy advised she could assist the First Nation participants in defining the scope/topics for
expert review, if requested by First Nation participants.
Enbridge Gas Inc. Presentations and Discussions related to:
• Overview of Enbridge Gas Inc. – led by Keith Boulton, Director Public Affairs & Ombudsman
• Energy Transition – led by Jennifer Murphy, Manager Carbon & Energy Transition Planning
• Demand Side Management (DSM) pilots and programs – led by Craig Fernandes, Manager Energy
Conservation Strategy & Policy and Tausha Esquega, Senior Advisor, Indigenous Energy Conservation
• Discussed DSM programs for Indigenous communities (e.g. Clean Home heating initiative, Greener homes
grant, home winterization program)
• Enbridge Gas Inc. advised the Clean Home heating initiative is a limited pilot funded by the provincial
(Ontario) government intended to target consumers who had broken air conditioners and to encourage
them to install a heat pump, but it is limited by postal code and the consumer receives a rebate of $4,500
if they install a hybrid system.
• Enbridge Gas Inc. advised it is the program administrator/delivery agent for the Greener Homes grant
program in Ontario; this is available in certain postal codes where rebates are provided to customers by
NRCan. If someone is interested in participating in this program they enter their postal code on Enbridge
Gas Inc.’s website to determine eligibility.
• Government initiatives tend to have restrictions (e.g. heat pump grants program is not available to First
Nation reserve customers). First Nation participants would like to know why these programs aren’t
available on reserve and would like to discuss this with government (e.g. Ontario, NRCan, ISC).
• Enbridge Gas Inc. advised it has programs that may be adapted to allow for a streamlined program
without upfront costs, starting with a possible pilot program.
• Enbridge Gas Inc. has hired Tausha Esquega to do outreach with Indigenous communities regarding DSM
programs.
• Enbridge Gas Inc. advised that the Home Winterization Program is targeted to First Nations and is funded
through gas rate payers. First Nations Engineering Services Limited is the delivery agent for on reserve.
Action Items
• Item 1: Indigenous parties to confirm their proposed third party experts for the issues above. Jennifer
Murphy to discuss scope with Nick Daube, if requested. Discussion may move forward with only one or
two experts proposed for the next meeting.
• Item 2: Enbridge Gas Inc. to confirm details of incentive programs
• Item 3: Enbridge Gas Inc. to discuss with the Natural Gas expansion team limitations on information that
can be shared in the IWG discussions without a Non-Disclosure Agreement recognizing public reporting
requirements of IWG.
• Item 4: Kate Kempton to follow up with John Burrows to see if he can present to the IWG.
2. NEXT MEETING
Next meeting will be held on Thursday December 14, 2023, at the Enbridge Gas Inc. office at 500 Consumers Road
North York, Ontario M2J 1P8. Meeting will begin at 9:00 and lunch and refreshments will be provided throughout
the day.
Note for next meeting: Nick Daube will correct the reference to the Gas Expansion Act, as the intent was to discuss
the Access to Natural Gas Act. Nick Daube will correct this on the Topic priority table.
Indigenous Working Group Report May 31, 2024 Appendix A Page 8 of 22
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Page 613
APPENDIX A – AGENDA FOR MEETING OF IWG ON OCTOBER 17, 2023
Enbridge Gas Inc. Indigenous Working Group meeting October 17,
2023 Participants
9:00-9:15 Safety Moment, Safety Orientation Lauren Whitwham
9:15-10:30 •Review and approve minutes from meetingon September 18, 2023
•Review objectives of IWG including budget
and participants
•Review Lisa DeMarco’s Letter to EGI dated Aug 23
•Alignment with OEB settlement agreement
All
10:30-10:45 Break
10:45-12:00 •Alignment with OEB settlement agreement
•Future meeting agenda and topic planning
session
All
12:00-1:00 Lunch (Overview of EGI) Keith Boulton, Enbridge Gas Inc.
1:00-2:30 Energy Transition discussion Jennifer Murphy, Enbridge Gas Inc.
2:30-2:45 Break
2:45-3:30 DSM (pilots, programs) Tausha Esquega, Craig Fernandes, Enbridge Gas Inc.
3:30-4:00 Next steps
Indigenous Working Group Report May 31, 2024 Appendix A Page 9 of 22
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Page 614
APPENDIX B – SUMMARY TABLE OF ISSUES BY NICK DAUBE
CICULATED PRIOR TO IWG MEETING AND UPDATED BY THE IWG ON OCTOBER 17, 2023
Priority Discussion Topics for IWG
Energy Transition Programs
Topic Suggested EGI
Representa�ves
Third Party Experts Target for Discussion
at Upcoming Mee�ngs
Current Status
Heat pump pilots No expert likely
needed but need
Crown (ISC, NRCAN)
and Ontario
representa�on
✓(1)
Energy efficiency
pilots ✓(5)
Geothermal hea�ng
pilots
(combined to be
Energy eff – emerging
technology)
✓(5)
Natural Gas Expansion Act (4) Update on status.Indigenous
communi�es’ status.
Economic Partnership
Topic Suggested EGI Representa�ves Third Party Experts Target for Discussion at Upcoming Mee�ngs
Current Status
Renewable natural gas Expert ✓(3)
Resilience and Adaptation
Topic Suggested EGI Representa�ves Third Party Experts Target for Discussion at Upcoming Mee�ngs Current Status
Stranded assets,
clean-up costs, other
risks arising from
poten�ally declining
customer base
Energy transi�on expert Expert Necessary ✓(2)
(Earliest discussions
can focus on proposed
roadmap, since this is a
complicated and long-
term discussion topic)
Need for, benefits of and cost of Energy
Transi�on
Expert (9)
Nature-based fire
preven�on and
response
✓(7)
Indigenous Working Group Report May 31, 2024 Appendix A Page 10 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 16 of 28
Page 615
Future of the IWG
Topic Suggested EGI Representa�ves Third Party Experts Target for Discussion at Upcoming
Mee�ngs
Current Status
Future of the IWG and
its use as a precedent ✓
(Ongoing discussion
topic.)
Energy Transition Matters of Specific Interest to Indigenous Parties
Topic Suggested EGI
Representa�ves
Third Party Experts Target for Discussion
at Upcoming
Mee�ngs
Current Status
Decarboniza�on of EGI’s
gas storage opera�ons,
including the use of
electric compressors
instead of gas
compressors
(8)
Analysis and ac�on plan
for addressing fugi�ve emissions across
pipelines, compressor
sta�ons, and other point sources
Iden�fy leaks in
system: GHG SAT
First Na�ons
exper�se Expert
(6)
Indigenous procurement
on maintenance of
Enbridge Gas assets
(10) Ongoing under
each category
Indigenous Working Group Report May 31, 2024 Appendix A Page 11 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 17 of 28
Page 616
Enbridge Gas Inc. Indigenous Working Group Minutes - Draft
Minutes of a meeting of the Indigenous Work Group (IWG) held on December 14,2023 at 9:00 a.m. EST at
Enbridge Gas Inc., 500 Consumers Road, North York, Ontario M2J 1P8.
PRESENT
Don Richardson (virtual) Three Fires Group
Emily Ferguson (virtual
Nick Daube (in-person)
Three Fires Group
Resilient LLP, Three Fires Group
John Glover (virtual) Minodahmun Development LP
Kate Kempton (in-person) Woodward and Company, Ginoogaming First Nation
Jordan George (virtual)
Kodi Deleary
Kettle and Stony Point First Nation
Chippewas of the Thames First Nation
Tracy Skye (in-person) Six Nations Natural Gas
Diana Audino (in-person) Enbridge Gas Inc.
Lauren Whitwham (in-person)
Sarah Taylor (virtual)
Enbridge Gas Inc.
Enbridge Gas Inc.
Sarah Crowell (virtual) Enbridge Gas Inc.
Brent Bullough (in-person) Enbridge Gas Inc.
Tania Persad (in-person)
Cara-Lynne Wade (in-person)
Enbridge Gas Inc.
Enbridge Gas Inc.
Henry Ren (virtual) Enbridge Gas Inc.
Jennifer Murphy (virtual)
Peter Mussio (virtual)
Islam Elsayed (in-person)
Enbridge Gas Inc.
Enbridge Gas Inc.
Enbridge Gas Inc.
Craig Fernandes (in-person) Enbridge Gas Inc.
Tausha Esquega (in-person) Enbridge Gas Inc.
ABSENT WITH REGRETS
Chief Sheri Taylor Ginoogaming First Nation
Caolan Lemke
Michelle Bomberry
Catherine Pennington
Woodward and Company
Six Nations Natural Gas
Enbridge Gas Inc.
1. MATTERS FOR DISCUSSION
Review of Agenda (attached at Appendix A) and Logistics.
- Nick Daube of Resilient LLP, representing Three Fires Group, chaired the meeting, consensus to continue
to rotate the facilitator/chair of each IWG meeting.
Indigenous Working Group Report May 31, 2024 Appendix A Page 12 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 18 of 28
Page 617
- Lauren Whitwham provided a safety moment on preventative home security and safety while away from
home during the holidays.
- IWG welcomed a new representative from the Chippewas of the Thames First Nation as agreed in the OEB
Settlement Agreement that any interested Indigenous Party would be included.
- IWG confirmed that the meetings should continue to be hybrid (in person but with a virtual option) to
ensure inclusion and accessibility.
- IWG discussed and approved the minutes of the October 17 IWG meeting as drafted.
1. Discussion led by Indigenous parties concerning status of retaining independent experts.
- Suggested the discussion on experts involve:
1. Deliverables – What we are asking the experts to put together.
2. Themes – Consideration of themes that have been raised so far and what we would need
comments on in conversation with experts.
3. Fees – General thinking on fees and how groups go about paying the experts.
- Deliverables
- Agreement that the experts shouldn’t be re-inventing the wheel, just offering supplemental
information.
- Experts are to offer advice that identifies and begins to think through at a high level what
supplemental work should be performed that speaks to risks, opportunities for First Nations and
identify the tracks that don’t already perform those tasks.
- Suggested a future presentation to the IWG by an expert (for example, a 90 minute presentation
by an Enbridge Gas Inc. representative like Cara-Lynne Wade or a member of Energy Transition
Planning group.
- Not looking for reports from the experts, an informative PowerPoint would be sufficient.
- Some discussion of the consequences of energy transition and how Enbridge Gas Inc. could help
with that.
- Themes
- Energy transition is the first topic where an expert would be helpful.
- Experts would need to provide insight on the challenges of energy transition, specifically those
faced by First Nations, including limitations in access to energy sources and energy alternatives.
Better understanding of range of possible futures for First Nations participation in
energy transition and possible programs that might help in these scenarios.
Analysis of areas where expert believes certain reports demonstrate weaknesses, such
as fugitive emissions.
- Would like to retain an expert who is approaching these issues and energy transition from a First
Nation’s perspective.
- Expert insight as to where additional effort should be made to the “average” model to account
for incessant financial poverty, remoteness, and lack of alternatives that First Nations face.
- Reiterated by Indigenous parties that economic reconciliation, highlighting the Truth and
Reconciliation Call to Action #92, and recognition of jurisdiction of traditional territory should be
at the forefront of the discussion. This could include rights-based jurisdiction expertise and
Indigenous Knowledge.
- Experts being considered by Indigenous parties:
- Pelino Colaiacovo - Morrison Park Advisors (Canada)
- AJ Golding - London Economics (Canada)
- Bruce Tsuchida - Brattle Group (US)
- Fees
- Indigenous parties confirmed the proposed experts have not yet been retained, and advised that
keeping the requests at a high level should keep the costs from hitting the higher limit of the
annual expert budget.
Indigenous Working Group Report May 31, 2024 Appendix A Page 13 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 19 of 28
Page 618
-Ensuring that the requests for work from the experts are purposeful – not asking for full reports,
just information that is not from the perspective of Enbridge Gas Inc.
-Billing should be done by scope of work instead of by hour.
-Regional Pathway Study
-In reference to the discussion of the Pathway study in the Enbridge Gas Inc. reply in the Rebasing
proceeding, Enbridge Gas Inc. noted that the next step in the energy transition is to look at what
a regional model, rather than provincial, would look like to properly reflect the actual customers,
their usage and the challenges they face.
-How to accommodate the drawing of regions to effectively include First Nations into the regions.
This is to ensure that in transition, customers are not stranded and there is no undo
harm done to them including costs, reliability of energy and consumer choice.
- Expert at the hearing for the Industrial Gas User Association, Dr. Asa S. Hopkins looked at
regional modeling and had a high-level idea of what it could include. Enbridge Gas Inc. has
undertaken to look through Dr. Hopkins’ ideas to determine what scope Enbridge Gas could
reasonably complete and in what timeline.
-This was proposed at the Ontario Energy Board (OEB), and there was discussion as to whether
this would be led by the OEB or Enbridge Gas.
2.Fugitive Emissions Presentation
-Presentation by Peter Mussio, Manager of Carbon Strategy at Enbridge Gas Inc.
-Topics of presentation were an overview of GHG emission sources, GHG reductions and targets, Fugitive
Emissions measurement plan, Federal Methane Regulations, current emissions reductions, and future
emission sources.
-Discussion of Enbridge Gas Inc. study of fugitive emissions of methane gas, and how methane is measured
and targets of reduction. Challenges with reductions are finding the technology that can detect the
smaller leaks.
-Emily Ferguson, who has expertise on fugitive emissions, commented on the measurement of methane
gas emissions.
-Proposed by Indigenous Parties to have Emily more involved in the study of fugitive emissions
with Enbridge Gas Inc. and the reporting on sources of fugitive emission.
-Enbridge Gas Inc. advised they are preparing a study and comparison of Enbridge Gas Inc.’s
system to other systems and the technology being used. Study targeted to be completed in May
2024. Enbridge Gas to confirm in mid-January whether Emily can participate in the study and use
funds from the IWG to assist her participation in the study.
- Future Action Item would be to review and discuss the report that will be sent to the OEB on fugitive
emissions in a meeting of the IWG.
3.Follow up on heat-pump discussion and Presentation
-Presentation by Energy Transition Team Craig Fernandes and Tausha Esquega with Enbridge Gas Inc. - a
return to the Energy Transition presentation from the October 17th IWG meeting.
-Using the Clean Home Heating Initiative as a contextual example for a possible pilot program for First
Nations who are Enbridge Gas customers. The heat pump programs are hybrid systems, so the pilot would
need to start in a community that is an existing Enbridge Gas Inc. customer. Due to regulation, funding of
the program must flow to gas rate payers.
-The purpose of the discussion was to seek IWG input for the Pilot on what its goals or objectives should
be, how it should be reported, any concerns with marketing heat pumps to First Nation Communities and
which communities would be amenable to hosting the pilot.
-Suggested that community members go door to door to market the program, look for a
community that tracks their energy usage, start with a more southern located community so the
Indigenous Working Group Report May 31, 2024 Appendix A Page 14 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 20 of 28
Page 619
heat pumps can be more effective, speak with First Nations Engineering Services to see how their
experience has been on retrofitting or implementation in the community.
- Enbridge Gas Inc. will be drafting a plan for a pilot program to start with a winter proofing program in
order to save costs and move into a heat pump program. The draft may include a selected community
with whom direct engagement has been started for an agreement to host the pilot.
4. Access to Natural Gas Act Discussion and Presentation
- Presentation from Don Richardson, Three Fires Group, recommending that the Natural Gas Expansion
Program be adapted so that it is heat technology agnostic.
- This would create an environment of competition for access to the funds and could offer First Nations
communities easier access to low-carbon solutions.
- Suggested the future of energy transition include pooling of funds and working with the Electric provider
to make rater payer money more applicable to energy transition.
- Enbridge Gas Inc. representative mentioned it is currently preparing a submission for the next phase of
the Access to Natural Gas Act and could consider including the comments from Indigenous parties if
provided to Craig Fernandes and Tausha Esquega with Enbridge Gas Inc. by mid-January.
Action Items
• Item 1: Enbridge Gas Inc. to provide map of its distribution system including connections to TC Energy
system.
• Item 2: Enbridge Gas Inc. to plan to present and discuss the Report on fugitive emissions that will be
submitted to the OEB with the IWG.
• Item 3: Enbridge Gas Inc. to increase information sharing about what is known of the volume, locations,
and mitigations of fugitive emissions.
• Item 4: Enbridge Gas Inc. Energy Transition team to determine how they can incorporate the expertise of
Emily Ferguson and utilize her input on fugitive emissions in the study.
• Item 5: Enbridge Gas Inc. to draft a scope for the pilot program, conduct direct engagement with selected
community for agreement to host and implement planning.
• Item 6: Enbridge Gas Inc. Energy Transition Team to return to the next IWG to discuss the winterization
program and DSM.
• Item 7: Indigenous parties that have comments on the Judicial Review that was filed by the Chiefs of
Ontario against the federal government about the Fuel Services Act to share their comments with
Enbridge Gas Inc. by mid-January 2024 so Enbridge Gas Inc. can consider including them in their
submission.
5. NEXT MEETING
Next meeting will be held on Tuesday February 27, 2024, at the Enbridge Gas Inc. office at 500 Consumers Road
North York, Ontario M2J 1P8. Meeting will begin at 9:00 and lunch and refreshments will be provided throughout
the day.
Indigenous Working Group Report May 31, 2024 Appendix A Page 15 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 21 of 28
Page 620
APPENDIX A – AGENDA FOR MEETING OF IWG ON DECEMBER 14, 2023
Time Matter Participants
9:00-9:15 Preliminary matters, safety moment,
approval of minutes.
Group
9:15-10:15 Discussion led by Indigenous Parties
concerning status of retaining
independent experts.
Group
EGI – Cara-Lynn Wade and Jennifer
Murphy
10:15-11:15 EGI presents on Fugitive Emissions EGI - Peter Mussio Group
11:15-12:00 Discussion of Access to
Natural Gas Act
Don Richardson
12:00-1:00 Lunch
1:00-1:45 Follow up on heat pumps
discussion and progress update
EGI - Craig Fernandes and Tausha Esquega
1:45-2:30 Discussion on potential for similar pilot
programs in DSM or geothermal (or other)
areas
EGI - Craig Fernandes and Tausha Esquega
2:30-3:00 Debrief and planning Group
Indigenous Working Group Report May 31, 2024 Appendix A Page 16 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 22 of 28
Page 621
Enbridge Gas Inc. Indigenous Working Group Minutes - Draft
Minutes of a meeting of the Indigenous Work Group (IWG) held on April 30,2024 at 9:00 a.m. EST at Enbridge
Gas Inc., 500 Consumers Road, North York, Ontario M2J 1P8.
PRESENT
Don Richardson (in-person) Minogi Corp
Emily Ferguson (virtual
Todd Jardine (virtual)
Reggie George (virtual)
Jessica Wakefield (in-person)
Nick Daube (in-person)
Minogi Corp
Three Fires Group
Three Fires Group
Three Fires Group
Resilient LLP, Three Fires Group, Minogi Corp
John Glover (virtual) Minodahmun Development LP
Kate Kempton (in-person) Woodward and Company, Ginoogaming First Nation
Jordan George (virtual)
Jennifer Mills (virtual)
Kettle and Stony Point First Nation
Chippewas of the Thames First Nation
Tracy Skye (in-person) Six Nations Natural Gas
Diana Audino (in-person) Enbridge Gas Inc.
Lauren Whitwham (in-person)
Tania Persad (in-person)
Enbridge Gas Inc.
Enbridge Gas Inc.
Brent Bullough (in-person) Enbridge Gas Inc.
Sarah Taylor (in-person) Enbridge Gas Inc.
Craig Fernandes (in-person) Enbridge Gas Inc.
Richard Brant (in-person) Enbridge Gas Inc.
Mark Shilliday (virtual)
Peter Mussio (virtual)
Sarah Crowell (virtual)
Enbridge Gas Inc.
Enbridge Gas Inc.
Enbridge Gas Inc.
Henry Ren (virtual) Enbridge Gas Inc.
Jody Whitney (virtual) Enbridge Gas Inc.
1.MATTERS FOR DISCUSSION
Review of Agenda (attached at Appendix A) and Logistics.
-Lauren Whitwham, Enbridge Gas Inc., chaired the meeting, consensus to continue to rotate the
facilitator/chair of each IWG meeting.
-Brent Bullough provided a safety moment. Lauren Whitwham proposed that going forward any interested
IWG members could share a safety or cultural moment at a future meeting.
-IWG welcomed additional Indigenous representatives from Three Fires Group and confirmed as per the
Ontario Energy Board (OEB) Settlement Agreement any interested Indigenous Party could be included in
the IWG.
-IWG confirmed that the meetings should continue to be hybrid (in person, but with a virtual option) to
ensure inclusion and accessibility.
-IWG discussed and approved the minutes of the December 14, 2023 IWG meeting.
Indigenous Working Group Report May 31, 2024 Appendix A Page 17 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 23 of 28
Page 622
1.Updates related to OEB Rebasing Proceeding
-Tania Persad provided an overview of the OEB Decision and Order EB-2022-0200, Enbridge Gas Inc.
Application for 2024 Rates – Phase 1 (Rebasing Decision) and its implications to the IWG.
o Details of the Rebasing Decision were discussed and explained to the IWG.
o Enbridge Gas advised that it has filed a Motion to Review with OEB (Review Motion) and a Notice
of Appeal with the Ontario Divisional Court. The Review Motion will be dealt with first but is
currently in abeyance until June. The OEB stayed part of the Rebasing Decision dealing with the
revenue horizon.
o Discussions of the Provincial Government’s proposed legislation, Bill 165, to set aside the
revenue horizon portion of the Rebasing Decision and to require the OEB to set a revenue
horizon through a generic proceeding that takes into account the views of impacted parties.
o Noted Enbridge Gas’s plan to file an amended notice of Review Motion, to remove at least the
revenue horizon issue.
-Phase 2 of the rebasing proceeding has commenced with Enbridge Gas’s evidence filed at the end of April
2024.
o The procedural order issued by the OEB and the issues included in the order were discussed.
-Kate Kempton on behalf of Ginoogaming gave notice to the group that Ginoogaming is thinking of
challenging Bill 165 on the basis that it is not tough on climate change and places an undue burden on
Indigenous groups who already pay a higher proportion of their income on basic living expenses including
natural gas costs.
o A request was made that Enbridge Gas Inc. consider changing its stance on the legislation and
voicing to the government that this legislation is not in the best interest of Indigenous groups.
o A request was made that a meeting in the future include both the Chief of Ginoogaming and a
high level representative of Enbridge Gas to discuss the direction Enbridge Gas is heading with
this.
-Kate Kempton, on behalf of Ginoogaming, spoke at length about Indigenous way of life including a much
more holistic and interconnected worldview and relationship to all beings, of caring for all beings and
Mother Earth. She spoke on how the Western worldview, which came to dominate North America
through colonialism, is atomistic, linear and based on dominance and exploitation of the Earth, which is
what has led to the catastrophe of climate change that threatens to be an extinction event. Unless and
until those who are responsible and profit from goods that cause climate change accept that the status
quo and incremental change will only see us to an extinction, and that fundamental change is necessary
now, we will fail. One of those is Enbridge, and we are appealing to Enbridge to learn from and work with
First Nations to make this fundamental shift away from gas, starting right now.
-Frustration by all IWG parties was shared about the recent IESO Expedited Long Term Procurement
process, where many clean energy projects were not selected for funding, including the battery storage
project between Enbridge Gas and Three Fires Group.
2.Updates on the Enbridge Gas fugitive emissions study.
-Presentation by Peter Mussio, Manager of Carbon Strategy at Enbridge Gas Inc. as requested by Don
Richardson and Minogi Corp.
-The presentation gave an outline and purpose of the study that has been completed, and a review of the
findings and technology that is available.
-The study was outlined to the group with explanations on the measurements and the technology review
that took place. The purpose of the study is to improve the accuracy of methane emissions being detected
and recorded, and determining which technology is best suited to measure these emissions on the
Enbridge Gas system. The goal is to implement this technology on the system to improve data accuracy to
help identify potential options for mitigation going forwards.
-Reviews of technology are being undertaken to determine potential capabilities to not only detect a
source, but to quantify the type of emission. Mobile ground detection is most effective and practical for
Indigenous Working Group Report May 31, 2024 Appendix A Page 18 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 24 of 28
Page 623
the system, and a pilot program using these methods is being created to develop a system specific
assessment.
-A final draft of the pilot program and assessment will be circulated to the Enbridge Gas consultant in the
next few weeks, and once finalized, will make a part of the deferral account in June.
-A request was made to promptly involve Emily Ferguson of Minogi Corp in the process, so she can be
involved in the next steps as much as possible. IWG members would like this to be a collaborative and
ongoing commenting process.
o Enbridge Gas will get in touch with Emily and facilitate a way to keep her more involved going
forward.
3.Presentation update on CGHG/HER+ programs, as requested by Minogi Corp.
-Presentation by Energy Conservation Team Craig Fernandes of EGI, on the wind down of CGHG/HER+.
-Program uptake was wildly successful such that the initial budget forecast for 2023-Q1 2027 was
exceeded on a forecast basis for the CGHG/HER+ federal program, and the entry was closed in Feb. 2024.
There was an amendment to increase the budget in order to include additional participants.
-A question was posed on whether there is specific funding allocated for Indigenous groups. Enbridge Gas
representative reiterated that the home winter proofing program (“HWP”) is better funded and suited
directly for Indigenous communities, and those interested in the CGHG/HER+ programs have been
directed by Enbridge Gas to pursue the route of HWP.
-A request was made to get in contact with Tasha Esquega with Enbridge Gas Inc. on the pilot program for
the Indigenous specific winter proofing and heat pump program and which communities have been
selected and/or consulted with for the pilot.
-It was confirmed that due to OEB restrictions on the funding allocation of the program, that they were
only open to Enbridge Gas customers, and those on other gas systems would not be covered under the
program – Six Nations Natural Gas customers would not be eligible.
o Request was made for Enbridge Gas to pen an informative email that Six Nations Natural Gas
may use to pass on to their community members about why they are not eligible as they are
customers of another gas utility – Six Nations Natural Gas.
4.Group discussion of the IWG Settlement Agreement Report for 2024 (IWG Report) and budget estimate for
2025.
-The IWG discussed the draft IWG Report and members pointed to any changes that they would like to see
in the report.
-A request was made to include additional detail in the IWG Report about the presentations that have
been provided during the IWG meetings.
-The Budget was discussed and an Action item for the Indigenous IWG members to discuss together and
propose a new budget for 2025 that will reflect what they believe they will need for representative
involvement and legal/consultant advice.
5.Updates on the retention of experts
-Brattle Group is close to being retained by the Indigenous parties. The main focus of Brattle Group as
contemplated by the Indigenous parties will be to review the expert reports from the rebasing application
and determine what is important information that may have been missed in those reports that would
help mitigate energy-related risks and identify energy-related opportunities of First Nation groups in
Ontario. There is also an expectation that other experts will be retained to address other significant issues
relevant to the IWG. A potential example of these additional topics is fugitive emissions.
6.IWG Indigenous Parties Coordinator
-Proposed that the IWG have a participant take on the role of an Indigenous parties coordinator. Jessica
Wakefield of Three Fires Group will start to take on that role with tasks such as canvasing the Indigenous
Indigenous Working Group Report May 31, 2024 Appendix A Page 19 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 25 of 28
Page 624
participants about any topics or items they would like to see on the agenda and who should be at the
table presenting for those topics.
7. Supply Chain Management (SCM) Indigenous Engagement.
- Presentation by Richard Brant, Supply Chain Analyst Indigenous Engagement at Enbridge Gas, at the
request of Three Fires Group.
- Topics of the presentation were the Enbridge Indigenous Peoples Policy, the reporting and the target
setting in SCM.
- The Indigenous Peoples Policy is focused on including opportunities for partnership, employment,
procurement, and equity participation, with a commitment to increase participation. SCM collects
information that is provided by communities of contractors and Indigenous businesses to create a
database of those companies. These companies have a leg up for bids against non-Indigenous companies
when all parties are competitive.
- There is an Enbridge enterprise-wide target of $1 billion to be spent over the course of 7 years on
Indigenous spend included in the Indigenous Reconciliation Action Plan (IRAP) published in September
2022. All money spent on Indigenous benefits from projects and operations across North America is
included in the target.
o A request was made that Enbridge Gas Inc. share more regional (Ontario-specific data, if
available).
- Kate Kempton on behalf of Ginoogaming indicated there are no penalties for not meeting these targets
and that this should change if the targets are going to be taken seriously. Would like a better emphasis on
strict wording and equity.
o Suggestion from Three Fires Group that equity be a commitment with Enbridge playing a role in
skill building, to facilitate employment in Projects as well as O&M and post-project restoration.
- Request from Ginoogaming that the next IWG meeting in July include an in-depth discussion about
procurement of Indigenous peoples and equity.
8. Enbridge Employment practices and opportunities presentation.
- Presentation from Jody Whitney and Mark Shilliday, Enbridge Inc. Senior strategist on Indigenous
Collaboration and Enbridge Inc. Indigenous Recruitment Advisor, to provide an update on the
employment practices and opportunities as requested by Three Fires Group. Mark Shilliday is the
Indigenous recruiting advisor and sources Indigenous talent and then advocates for the Indigenous talent
when positions become available within the company. Mark shared many of the categories in which
Indigenous peoples have filled roles recently in Enbridge corporate.
- An overview of the Indigenous wellness program, funds and the Indigenous Employee Resource Group
was provided.
- The numbers and data collected is for Enbridge Corporate, as the jobs in the field with contractors are
largely restricted by Unions, especially in Ontario. Enbridge has had discussions with these Unions to seek
exemptions where possible and have had some success in Thunder Bay.
- A request to provide, or compile if not already available, more specific Ontario numbers as well as
providing the presentation to the IWG.
Action Items
• Item 1: Enbridge Gas Inc. to incorporate a list with a description of the presentations given to the IWG
during meetings in the IWG Report.
• Item 2: Enbridge Gas Inc. to request an update from Tasha Esquega with Enbridge Gas Inc. on the pilot
program for the Indigenous specific winter proofing program and which communities have been selected
and/or consulted with for the pilot.
Indigenous Working Group Report May 31, 2024 Appendix A Page 20 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 26 of 28
Page 625
• Item 3: Enbridge Gas Inc. Energy Transition team will determine how they can incorporate the expertise of
Emily Ferguson and utilize her input on fugitive emissions.
• Item 4: Enbridge Gas Inc. to draft information about the qualifications for the Home Heating Initiative for
Six Nations Natural Gas to disseminate to inquiring community members.
• Item 5: Enbridge Gas Inc. to share the presentation materials on the topics of Employment Practices and
Opportunities and SCM Indigenous Engagement to IWG members.
• Item 6: Enbridge Gas Inc. to share letter to the OEB on the HER+ replacement program offer with IWG
members.
• Item 7: Indigenous Parties to discuss the budget they will require for 2025 to be included in the IWG
Report and provide this information to Enbridge Gas.
9. NEXT MEETING
Next meeting will be held on Tuesday, July 30, 2024, 9:00 a.m. at the Enbridge Gas Inc. office at 500 Consumers
Road North York, Ontario M2J 1P8. Jessica Wakefield of Three Fires Group will be facilitating the meeting and
acting as IWG Coordinator. She will canvass Indigenous IWG members on topics they would like to discuss at the
next meeting.
Indigenous Working Group Report May 31, 2024 Appendix A Page 21 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 27 of 28
Page 626
APPENDIX A – AGENDA FOR MEETING OF IWG ON APRIL 30, 2024
Time Matter Participants
9:00-9:15 a.m. Safety moment, introductions, administrative matters, status of
action items, approval of minutes
Group
9:15-9:30 a.m. Enbridge Gas Notice of Appeal and Filing of Review Motion with
the OEB regarding Phase 1 rebasing decision
Tania Persad, Associate General
Counsel, Enbridge Gas
9:30-10:00 a.m. OEB Rebasing reporting – IWG report Group review
10:00-10:30 a.m. Fugitive Emissions Update – Progress on Enbridge study on
available technologies and potential involvement of Emily
Ferguson in the study. Consideration of funding support through
capacity funding for IWG.
Peter Mussio, Manager, Carbon
Strategy, Enbridge Gas
10:30-11:00 a.m. Federal Greener Homes Program update and how the changes
will affect Enbridge’s offerings and role as a provider
Craig Fernandes, Manager Residential
Energy Conservation, Enbridge Gas
11:00-11:15 a.m. Break
11:15-12:00 p.m. Independent Expert/Speaker schedule:
-Energy Transition
-Fugitive Emissions (Tie to anticipated May 2024
technology study release)
-Economic Reconciliation
-Rights-based Jurisdiction
-Indigenous Knowledge
Group
12:00-1:00 p.m. Lunch
1:00-2:00 p.m. EGI’s Indigenous procurement policy; Reporting and target-
setting; Efforts to proactively identify procurement
opportunities for Indigenous participants; Capacity building
efforts; employment policies and opportunities relating to
construction projects
Richard Brant, SCM Indigenous
Engagement, Enbridge
2:00-3:00 p.m. EGI’s Indigenous employment practices; general corporate
policies and opportunities
Jody Whitney, Sr Strategist Indigenous
Collaboration
Mark Shilliday, Indigenous Recruitment
Advisor, Enbridge
3:00-3:30 p.m. Next steps, future meetings etc. Group
Indigenous Working Group Report May 31, 2024 Appendix A Page 22 of 22
Filed: 2024-05-31, EB-2024-0125, Exhibit H, Tab 1, Schedule 2, Page 28 of 28
Page 627
This hearing will be held under section 36 of the Ontario Energy Board Act, 1998.
Ce document est aussi disponible en français.
If the application is approved as filed, then a typical residential customer and a typical general service
customer of Enbridge Gas Inc. would see the following one-time billing adjustments, effective
January 1, 2025:
EGD Rate Zone (former Enbridge Gas Distribution Inc. customers)
• Residential Rate 1 Sales Service and Direct Purchase customers will see a one-
time billing credit of $5.12, effective January 1, 2025.
Union Rate Zone (former Union Gas Limited customers)
• Union South Residential Rate M1 Sales Service customers will see a one-time billing
charge of $9.51, effective January 1, 2025.
• Union South Residential Rate M1 Direct Purchase customers will see a one-time
billing charge of $1.60, effective January 1, 2025.
• Union North-West Residential Rate 01 Sales Service and Direct Purchase
customers will receive a one-time billing charge of $0.13, effective January 1, 2025.
• Union North-East Residential Rate 01 Sales Service and Direct Purchase
customers will see a one-time billing charge of $0.47, effective January 1, 2025.
Other customers, including businesses, may also be affected. It is important to review the application
carefully to determine whether you may be affected by the proposed changes.
Under the OEB-approved Earnings Sharing Mechanism, Enbridge Gas Inc. is required to share
with customers any earnings that are 150 basis points over the OEB-approved return on equity.
Enbridge Gas Inc. says that its 2023 earnings were below the 150 basis point threshold and as
a result it is not proposing to share any earnings with customers.
Enbridge Gas Inc. has applied to dispose of the balances of certain deferral and variance accounts.
Page 628
This hearing will be held under section 36 of the Ontario Energy Board Act, 1998.
Ce document est aussi disponible en français.
There are three types of OEB hearings: oral, electronic and written. The applicant has applied for a
written hearing. The OEB is considering this request. If you think a different hearing type is
needed, you can write to us to explain why.
During this hearing, we will hear questions and arguments from participants about this case. We will
also hear questions and arguments from participants that have registered as Intervenors. After the
hearing, we will decide whether to approve the application.
HAVE YOUR SAY
You have the right to information about this
application and to participate in the process.
Visit www.oeb.ca/notice and use file number
EB-2024-0125 to:
• Review the application
• File a letter with your comments
• Apply to become an intervenor
PRIVACY
IMPORTANT DATES
You must engage with the OEB on or before
July 15, 2024 to:
• Provide input on the hearing type (oral,
electronic or written)
• Apply to be an intervenor
If you do not, the hearing will move forward
without you, and you will not receive any further
notice of the proceeding.
If you write a letter of comment, your name and the content of your letter will be put on the public
record and the OEB website. If you are a business or if you apply to become an intervenor, all the
information you file will be on the OEB website.
COST AWARDS
The OEB intends to consider cost awards in this proceeding that are in accordance with the
Practice Direction on Cost Awards and only in relation to the following:
1) The review of the following deferral and variance accounts:
Enbridge Gas Inc. Accounts
• Tax Variance - Accelerated Capital Cost Allowance – Enbridge Gas Inc.
• Integrated Resource Planning Operating Costs Deferral Account
• Getting Ontario Connected Act Variance Account
• Accounting Policy Changes Deferral Account (2019-2023)
EGD Rate Zone (former Enbridge Gas Distribution Inc.) Accounts
Page 629
This hearing will be held under section 36 of the Ontario Energy Board Act, 1998.
Ce document est aussi disponible en français.
• Storage and Transportation Deferral Account
• Transactional Services Deferral Account
• Unaccounted for Gas Variance Account
• Average Use True-Up Variance Account
• Deferred Rebate Account
• OEB Cost Assessment Variance Account
• Incremental Capital Module Deferral Account (2020-2023)
• RNG Injection Service Variance Account (2022-2023)
Union Rate Zones (former Union Gas Limited) Accounts
• Upstream Transportation Optimization Deferral Account
• Unabsorbed Demand Costs Variance Account
• Short-Term Storage and Other Balancing Services
• Normalized Average Consumption Deferral Account
• Deferral Clearing Variance Account
• OEB Cost Assessment Variance Account
• Parkway West Project Costs Deferral Account
• Lobo D/Bright C/Dawn H Compressor Project Costs Deferral Account
• Panhandle Reinforcement Project Costs Deferral Account
• Incremental Capital Module Deferral Account (2019-2023)
• Unaccounted for Gas Price Variance Account
2) The review of Enbridge Gas Inc.’s 2023 earnings, earnings sharing calculations and the 2023
Performance Scorecard.
3) The review of the methodology for disposing and allocating the deferral and variance account
balances.
Enbridge Gas Inc.
1-866-763-5427
Monday - Friday 8:30 AM - 6:00 PM
enbridgegas.com
Page 630
Cette audience sera tenue en vertu de l’article 36 de la Loi de 1998 sur la Commission de l’énergie de l’Ontario.
This document is also available in English.
Si la demande est approuvée telle quelle, la facture d’un client résidentiel type et d’un client
de services généraux type d’Enbridge Gas Inc. subira les ajustements ponctuels suivants à
compter du 1er janvier 2025 :
Zone de tarification d’EGD (anciens clients d’Enbridge Gas Distribution Inc.)
• Les clients en achat direct et les clients de la zone tarifaire de services
résidentiels 1 constateront un crédit unique sur facture de 5,12 $ à compter du
1er janvier 2025.
Zone de tarification d’Union (anciens clients d’Union Gas Limited)
• Les clients de la zone tarifaire de services résidentiels M1 d’Union Sud
constateront la facturation d’un montant tarifaire unique de 9,51 $ à compter du
1er janvier 2025.
• Les clients en achat direct de la zone tarifaire de services résidentiels M1
d’Union Sud constateront la facturation d’un montant tarifaire unique de 1,60 $ à
compter du 1er janvier 2025.
• Les clients en achat direct et les clients de la zone tarifaire de services
résidentiels 01 d’Union Nord-Ouest recevront un montant tarifaire unique sur facture
de 0,13 $ à compter du 1er janvier 2025.
• Les clients en achat direct et les clients de la zone tarifaire de services
résidentiels 01 d’Union Nord-Est constateront la facturation d’un montant tarifaire
unique de 0,47 $ à compter du 1er janvier 2025.
Les autres clients, dont les entreprises, pourraient également être concernés. Il est important
d’examiner la requête attentivement afin de déterminer si vous serez concernés par les
changements proposés.
En vertu du mécanisme de partage des gains approuvé par la CEO, Enbridge Gas Inc. est
tenue de partager avec ses clients tout bénéfice qui dépasse de 150 points de base le
Enbridge Gas Inc. a demandé la liquidation des soldes de certains comptes de report et d’écart.
Avis de la Commission de l’énergie de
l’Ontario aux clients d’Enbridge Gas Inc.
Page 631
Cette audience sera tenue en vertu de l’article 36 de la Loi de 1998 sur la Commission de l’énergie de l’Ontario.
This document is also available in English.
rendement des capitaux propres approuvé par la CEO. Enbridge Gas Inc. affirme que ses
bénéfices pour l’exercice 2023 étaient inférieurs au seuil de 150 points de base et, par
conséquent, elle ne propose pas de partager les bénéfices avec ses clients.
Il existe trois types d’audiences à la CEO : les audiences orales, les audiences électroniques
et les audiences écrites. Le requérant a demandé une audience écrite. La CEO examine
actuellement cette demande. Si vous estimez qu’avoir recours à un autre type d’audience
serait préférable, vous pouvez écrire à la CEO pour lui présenter vos arguments.
Au cours de cette audience, nous entendrons les questions et les arguments des participants
sur cette affaire. Nous entendrons également les questions et arguments des participants
inscrits en tant qu’intervenants. Après l’audience, nous déciderons d’approuver ou non cette
requête.
DONNEZ VOTRE AVIS
Vous avez le droit d’être informés au sujet de
cette requête et de participer au processus.
Visitez le site www.oeb.ca/fr/participez et
utilisez le numéro de dossier
EB-2024-0125 pour :
• examiner la requête;
• envoyer une lettre comportant vos commentaires;
• présenter une demande pour devenir
un intervenant.
PROTECTION DES RENSEIGNEMENTS PERSONNELS
DATES IMPORTANTES
Vous devez communiquer avec la CEO au plus
tard le
juillet 15 2024 pour :
• fournir des renseignements sur le type
d’audience (orale, électronique ou
écrite);
• présenter une demande en vue de devenir
un intervenant.
À défaut de cela, l’audience se déroulera sans
vous et vous ne recevrez plus d’avis dans le
cadre de la présente procédure.
Si vous écrivez une lettre de commentaires, votre nom et le contenu de cette lettre seront
ajoutés au dossier public et au site Web de la CEO. Si vous êtes une entreprise ou si vous
demandez à devenir un intervenant, tous les renseignements que vous déposez seront
disponibles sur le site Web de la CEO.
ADJUDICATION DES FRAIS
La CEO envisage d’accorder, dans la présente affaire, une adjudication des frais
conformément aux Directives de pratique concernant l’adjudication des frais, et uniquement
À SAVOIR
Page 632
Cette audience sera tenue en vertu de l’article 36 de la Loi de 1998 sur la Commission de l’énergie de l’Ontario.
This document is also available in English.
en ce qui concerne les éléments suivants :
1) L’examen des comptes de report et d’écart suivants :
Comptes d’Enbridge Gas Inc.
• Écart de taxe – attribution accélérée des coûts
d’immobilisations – Enbridge Gas Inc.
• Compte de report des coûts d’exploitation de la planification intégrée des
ressources
• Compte d’écart lié à la Loi pour un Ontario connecté
• Compte de report pour la modification de la méthode comptable (de 2019 à 2023)
Comptes de la zone de tarification d’EGD (anciennement Enbridge Gas Distribution Inc.)
• Compte de report pour l’entreposage et le transport
• Compte de report des services transactionnels
• Compte d’écart lié au gaz non comptabilisé
• Compte d’écart égalisé de l’utilisation moyenne
• Compte de remise différée
• Compte d’écart pour l’évaluation des coûts de la CEO
• Compte de report du module lié au capital supplémentaire (de 2020 à 2023)
• Compte d’écart du service d’injection de GNR (de 2022 à 2023)
Comptes de zones de tarification d’Union (anciennement Union Gas Limited)
• Compte de report pour l’optimisation du transport en amont
• Compte d’écart lié aux coûts de la demande non absorbée
• Stockage à court terme et d’autres services d’établissement de bilan
• Compte de report pour la consommation moyenne normalisée
• Compte d’écart pour la compensation des reports
• Compte d’écart pour l’évaluation des coûts de la CEO
• Compte de report des coûts du projet Parkway West
• Compte de report des coûts du projet du compresseur de Lobo D, Bright C et
Dawn H
• Compte de report des coûts du projet de renforcement Panhandle
• Compte de report du module lié au capital supplémentaire (de 2019 à 2023)
• Compte d’écart lié au prix du gaz non comptabilisé
2) L’examen des bénéfices de l’exercice 2023 d’Enbridge Gas Inc., les calculs de partage
des bénéfices et la fiche de pointage du rendement de l’exercice 2023.
3) L’examen de la méthodologie pour liquider et allouer les soldes des comptes de report
et d’écart.
Page 633
Cette audience sera tenue en vertu de l’article 36 de la Loi de 1998 sur la Commission de l’énergie de l’Ontario.
This document is also available in English.
Enbridge Gas Inc.
1 866 763-5427
Du lundi au vendredi, de 8 h 30 à 18 h
enbridgegas.com
EN SAVOIR PLUS
Page 634