May 29, 2025 Sent via email Ms. Sarah Walsh Director, Regulatory Affairs FortisBC Energy Inc. 16705 Fraser Highway Surrey, BC V4N 0E8 gas.regulatory.affairs@fortisbc.com
Re:
Sara Hardgrave Acting Commission Secretary
Commission.Secretary@bcuc.com bcuc.com
Suite 410, 900 Howe Street Vancouver, BC Canada V6Z 2N3 P: 604.660.4700 TF: 1.800.663.1385
Letter L-7-25
FortisBC Energy Inc. – 2025/2026 Annual Contracting Plan for the period November 1, 2025 to October 31, 2026
Dear Ms. Walsh: On May 1, 2025, FortisBC Energy Inc. (FEI) filed with the British Columbia Utilities Commission (BCUC), on a confidential basis, its 2025/2026 Annual Contracting Plan (ACP) for the gas year starting November 1, 2025 and ending October 31, 2026 (2025/2026 ACP). The BCUC accepts the 2025/2026 ACP and items as set out on pages 12 to 15 of the confidential 2025/2026 ACP. The major portfolio recommendations included in the 2025/2026 ACP are as follows:
1. Forecast Design Peak Day Demand: FEI recommends a peak day value for 2025/2026 of 1,462 TJ/day, an increase of 10 TJ/day from the amounts approved in the 2024/2025 ACP.
2. Annual Normal Demand: Annual normal demand for 2025/2026 is forecast at approximately 159 PJ resulting in an average daily normal load of 436 TJ/day. In 2024/2025, the total annual normal demand was forecast to be 158 PJ that resulted in a daily normal load of 432 TJ/day.
3. RNG Demand: The normalized forecast demand for RNG for 2025/2026 is 22 TJ/day. 4. Commodity Portfolio: FEI recommends taking the normalized forecast demand for Core Customers (436 TJ/day) and reducing it by the normalized forecast demand amount of RNG (22 TJ/day) as the Daily Baseload Gas Supply required for Core Customers (414 TJ/day).
5. Commodity Portfolio: FEI recommends continuing the current receipt point allocation percentages of 75% at Station 2 and 25% at AECO/NIT.
6. Commodity Portfolio: For the period November 1, 2024 to October 31, 2025, the receipt point fuel gas percentages are 4.5% at Station 2 and 1.3% at AECO/NIT. FEI will evaluate and communicate before October 2025 the Commodity Providers’ fuel requirements for gas delivery on November 1, 2025.
7. Commodity Portfolio: FEI recommends continuing with a balanced mix of daily and monthly priced supply to provide operating flexibility and to mitigate adverse price movements.
8. Commodity Portfolio: FEI recommends consideration of longer-term supply contracts with producers and other key suppliers at Station 2, up to ten years in length based off different pricing structures, in the interest of pricing diversity and supply security at the Station 2 market hub.
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9. Commodity and Midstream Portfolio: FEI recommends term purchases at Station 2 out to the 2028/2029 gas year in the interest of pricing diversity and supply security at Station 2.
10. Commodity and Midstream Portfolio: FEI recommends evaluating options involving additional infrastructure (on-system storage, market area storage and/or pipeline infrastructure), in order to increase gas supply resiliency, security of supply and diversity of supply in FEI’s portfolio of resources.
11. Midstream Portfolio: FEI recommends maintaining existing physical resources for the 2025/2026 gas year, which includes storage, and transportation capacity on Westcoast’s T-South and T-North, TC Energy’s NGTL and Foothills BC system, and Northwest Pipeline’s system.
12. Midstream Portfolio: FEI recommends negotiating over a ten-month period from January 2026 to October 2026 for the 2026/2027 winter supply transactions at Station 2.
13. Midstream Portfolio: FEI recommends having pipeline capacity and call option arrangements available as contingency resources.
The BCUC requests FEI to file its 2026/2027 ACP by May 1, 2026. In addition, the BCUC requests FEI to include the following information in the 2026/2027 ACP:
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An update on the storage and transport requirements and alternatives for the 2026/2027 contracting year and future contracting years, including analysis on how to optimize the amounts of transportation and storage to be contracted in future years, taking into account the regional infrastructure and market developments currently in place and anticipated to be in place in the future, including, but not restricted to: Tilbury development; Westcoast pipeline; T-South pipeline expansion; Woodfibre LNG; and the Huntingdon market;
An update to the Northeastern BC market study; An update on the efforts to establish key relationships with producers who plan to develop supply in the Horn River, Montney and other producing regions of British Columbia over the long term;
An update and analysis of the operational experience with Mt. Hayes and Tilbury LNG peaking resources for the 2025/2026 contracting year, including an analysis of the potential impact of changing LNG loads under RS 46 service on the availability of these peaking resources for the core natural gas customers for the 2025/2026 and future years, as well as storage levels;
A load forecast for RS 46 customers and the supply arrangements for meeting these customers’ load requirements;
An update on how FEI will meet Fort Nelson supply needs in the future considering that NorthRiver Midstream has announced the suspension of its operations;
An update on whether the current solution to backflow the Fort Nelson supply using the Westcoast system still remains the most viable and any other necessary updates regarding the service area;
An update on FEI’s strategy for incorporating renewable natural gas and other lower carbon gas into its 2026/2027 and future ACPs; and
An update on FEI’s progress in incorporating the initiatives in its Long Term Resource Plan into its ACP strategies as it pertains to the energy transition.
Pursuant to section 71 of the Utilities Commission Act (UCA) and in accordance with the BCUC Rules for Natural Gas Energy Supply Contracts, FEI is requested to submit applications for all energy supply and storage contracts along with any information it considers necessary for the BCUC to determine whether the contract is in the public interest. The BCUC expects that where an application concerns a longer-term supply commitment (10 or
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more years), FEI will thoroughly describe the associated benefits and risks. Each application will be reviewed based on the considerations outlined in section 71(2.1) of the UCA and the prevailing market conditions at that time.
Exclusive of the non-confidential Executive Summary, the BCUC will hold the 2025/2026 ACP confidential, as it contains commercially sensitive information, unless the BCUC determines otherwise. A copy of FEI’s non-confidential Executive Summary of the FEI 2025/2026 ACP is attached as Appendix A.
Sincerely, Electronically signed by Sara Hardgrave Sara Hardgrave Acting Commission Secretary
BV/kk Enclosure
FEI 2025/2026 ACP
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FORTISBC ENERGY INC. 2025/2026 ANNUAL CONTRACTING PLAN - EXECUTIVE SUMMARY
EXECUTIVE SUMMARY 1 INTRODUCTION Pursuant to section 15 of the British Columbia Utilities Commission (BCUC) Rules for Natural Gas Energy Supply Contracts, FortisBC Energy Inc. (FEI) files this non-confidential executive summary of its 2025/2026 Annual Contracting Plan (2025/2026 ACP), which FEI is seeking acceptance of by the BCUC. In the 2025/2026 ACP, FEI sets out the forecast load requirements for Rate Schedules (RS) 1 to 7 and 46 customers (Core customers) for all of its natural gas service areas 1 and the gas supply and other resources FEI proposes to meet those requirements for the upcoming gas year (November 1, 2025 to October 31, 2026). The 2025/2026 ACP also includes the information that the BCUC directed FEI to include in its acceptance letter of the 2024/2025 Annual Contracting Plan (2024/2025 ACP). 2
The objectives for the 2025/2026 ACP remain consistent with recent annual contracting plans (ACPs) accepted by the BCUC, and are as follows:
1. To contract for resources that ensure a balance of security, diversity and reliability of gas supply in order to meet the Core customer forecast design peak day and annual requirements, while minimizing the overall cost of the portfolio.
2. To develop a mix of resources in the portfolio that provides flexibility in the contracting of resources based on short-term and long-term planning considerations, and evolving market dynamics.
Aligned with these objectives, in the 2025/2026 ACP, FEI continues to focus on short- to long-term contracting strategies for storage, supply (conventional and renewable natural gas), and pipeline transportation resources to meet the peak day, winter design, and normal load requirements for future gas years. Engaging in planning for beyond the next gas year is essential, as the resources available for inclusion in the ACP are limited, may require long lead times to adjust, and are subject to changing market conditions.
Since the October 9, 2018 pipeline rupture and the capacity restrictions imposed thereafter on the Westcoast Energy Inc. (Westcoast) 3 T-South system (T-South Incident), FEI has placed more emphasis on enhancing gas supply resiliency within its portfolio. This includes holding excess T-South capacity as contingency resources 4 and increasing diversity of supply by taking back capacity on the Southern Crossing Pipeline (SCP). 5 These decisions have proven to be critical as FEI has experienced several other supply disruptions since the T-South Incident. FEI is
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Service areas include Lower Mainland, Inland, Columbia, Fort Nelson, Whistler, and Vancouver Island. BCUC Letter L-13-24 dated June 7, 2024. Westcoast is a subsidiary of Enbridge Inc. Contingency resources are resources (e.g., supply, LNG, and pipeline infrastructure) above the current load forecast for Core customers that can be called on if planned resources are unexpectedly not available or insufficient to meet demand. A portion of pipeline capacity on the SCP was historically contracted out to regional parties. However, FEI took back this capacity effective November 1, 2020, as it was the only opportunity for FEI to diversity its supply portfolio.
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continuing to look for options to mitigate future supply risks for Core customers, which may increase the cost of the gas supply portfolio.
The contracting flexibility of FEI’s portfolio is also emerging as a greater area of focus, particularly due to planning uncertainties that may lead to future increases or decreases in FEI’s Core customer demand. Within the confidential sections of the 2025/2026 ACP, FEI elaborates on how the existing portfolio of resources is adaptable to address potential reductions in conventional natural gas, but there is a pressing need for additional infrastructure in the region to enhance flexibility, ensuring the maintenance of the strategies outlined in the ACP.
1.1 Sources of Regional Gas Supply Resources The locations where FEI can purchase its gas supply resources and the physical gas storage and pipeline resources that FEI has access to are the foundation of FEI’s gas supply planning within its ACPs. For orientation, Figure ES-1 provides an overview of FEI’s operating region, the gas supply basins that serve the Pacific Northwest markets, the transportation pipelines and storage facilities required by these markets, and the location of the trading hubs where commodity purchases are transacted.
Figure ES-1: Regional Supply Resources – Pipelines, Storage and Trading Hubs
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The majority of FEI’s natural gas supply is contracted at the supply hubs of Station 2 in Northeast BC and AECO/NIT (NOVA Inventory Transfer) in Alberta and transported to FEI’s system by third-party pipelines. FEI also has the option to purchase supply at market hubs on the international border at Huntingdon/Sumas and East Kootenay/Kingsgate, which are directly connected to FEI’s system. Purchasing supply at these latter market hubs allows FEI to avoid contracting for capacity on third-party pipelines, but comes with the disadvantage of increased supply and pricing risks under certain market conditions, which are discussed within the confidential sections of the 2025/2026 ACP.
FEI contracts seasonal storage with Aitken Creek Gas Storage ULC (Aitken Creek) in Northeast BC and a small portion with Rockpoint Gas Storage (Rockpoint) in Alberta. These seasonal storage assets are available to be utilized throughout the winter season as needed. FEI also contracts for shorter-duration market area storage resources at Jackson Prairie in Washington and Mist in Oregon.
To facilitate the purchase of gas supply from various sources and to manage withdrawals and injections from storage facilities for delivery to FEI’s transmission system, FEI contracts with third parties for transportation services. Contracting for transportation capacity on Westcoast’s T-North and T-South system provides FEI with the principal access to gas supply from Northeast BC, which is mainly purchased at the Station 2 market hub, and supply that is withdrawn from Aitken Creek. Contracting for capacity on TC Energy’s NGTL 6 and Foothills BC 7 systems, and utilizing FEI’s own SCP, allows FEI to access gas supply from the AECO/NIT and East Kootenay/Kingsgate markets and Alberta-located storage facilities. Finally, transportation capacity on Williams’ Northwest Pipeline (Northwest Pipeline) provides access to redeliveries from storage facilities south of the international border in Washington and Oregon states.
FEI utilizes its own on-system LNG storage facilities at Tilbury and Mt. Hayes to provide short duration high volume gas supply during periods of cold winter weather or during emergency situations. These are the only on-system physical storage resources that FEI has control over to protect its system. Importantly, they are not impacted by third-party transportation or storage capacity disruptions.
1.2 Portfolio Development Method To develop an effective portfolio, FEI needs to plan for the likely maximum load during an extreme cold weather event, or series of events, so that sufficient resources are identified that FEI can call on to meet that requirement. Therefore, key inputs to the ACP are FEI’s five-year peak day forecast, and FEI’s design and normal load forecasts. These forecasts provide an estimate of the
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Effective April 1, 2024, ownership of the NGTL natural gas transmission system in Western Canada transferred from NOVA Gas Transmission Ltd. to NGTL GP Ltd., general partner on behalf of NGTL Limited Partnership, a wholly owned subsidiary of TransCanada PipeLines Limited, an affiliate of TC Energy Corporation. The transfer will not involve any change in operation. Foothills BC pipeline system owned by Foothills Pipe Lines Ltd., a wholly owned subsidiary of TransCanada PipeLines Limited, an affiliate of TC Energy Corporation.
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normal baseload that FEI needs to serve for 365 days and the potential load that FEI may need to serve when cold weather is experienced during the winter period.
Once the forecast load is known, potential supply options are identified, which become inputs into the PLEXOS portfolio optimization model. 8 This model aims to develop an optimized gas supply portfolio that minimizes costs for FEI’s customers. PLEXOS also allows FEI to run scenarios to determine the sensitivity of the portfolio to changes in the forecast and the potential availability of regional resources. The final portfolio is reviewed for reasonableness and continues to have adjustments based on the experience of managers in Gas Supply.
1.3 The Essential Services Model (ESM) for Gas Delivery FEI also develops its portfolio to take into account the Customer Choice Program, which allows residential and commercial customers to choose to enter a fixed-term, fixed-rate contract with a licensed Gas Marketer for their commodity requirements. FEI implemented the ESM to enable the Customer Choice Program. FEI, in its role of manager of midstream resources, is referred to as “FEI Midstream”, while in its role as a Commodity Provider to customers that are not part of the Customer Choice Program, FEI is referred to as “FEI Commodity”. Under the ESM, Commodity Providers (FEI Commodity and Gas Marketers) provide the daily baseload gas required for Core customers. Commencing with the 2025/2026 ACP, the daily baseload gas is determined by taking the normalized forecast demand for Core customers and reducing it by the normalized forecast demand amount of RNG to be delivered through the RNG Blend Service 9 and the Voluntary RNG Service 10 to sales customers (Daily Baseload Gas Supply). This is explained further in Section 3.2 of this Executive Summary. Meanwhile, FEI Midstream manages the midstream portfolio for all Core customers and any variations between the actual daily load and the Daily Baseload Gas Supply from Commodity Providers.
2 MAJOR PORTFOLIO RECOMMENDATIONS (2025/2026 ACP) FEI requests acceptance by the BCUC of the recommendations for FEI’s resource portfolio for the 2025/2026 gas year as set out in the 2025/2026 ACP and summarized to protect confidential information in the following sections.
As with past ACPs, the resource portfolio developed for the 2025/2026 ACP is grouped into two components: the Commodity portfolio and the Midstream portfolio. The Commodity portfolio includes the Daily Baseload Gas Supply, which is required for the full gas year, while the Midstream portfolio includes the seasonal supply, transportation capacity, storage, and LNG, which is required during the winter period. FEI gas supply manages these two components on
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FEI replaced the SENDOUT software for the 2025/2026 ACP, as the software was approaching its end-of-life with
the current vendor having no plans for future upgrades. Customers that have voluntarily selected RNG for their gas usage. The percentage can range between 5 percent and 100 percent of RNG.
9 A percent of RNG, from 0 to 100 percent pursuant to the RNG Blend Service. 10
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an integrated basis; however, for the purpose of the ACP, FEI has separated the two as FEI Commodity and FEI Midstream.
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Non-Confidential Version of Recommendations for the Commodity and Midstream Portfolios
Forecast Design Peak Day Demand for 2025/2026 • FEI’s forecast peak demand is 1,462 terajoules per day (TJ/day) 11 for 2025/2026, which represents a 10 TJ/day increase from the forecast for 2024/2025.
Forecast Annual Normal Demand for 2025/2026 • FEI’s normalized forecast daily demand for 2025/2026 is 436 TJ/day, which represents a 4 TJ/day increase from the forecast for 2024/2025.
Renewable Natural Gas (RNG) Demand and Supply for 2025/2025 • FEI’s normalized forecast RNG demand is 22 TJ/day for 2025/2026. The anticipated 12 amount of RNG supply for 2025/2026 is approximately 33 TJ/day. The ACP strategy to handle the 11 TJ/day difference between the anticipated amount of RNG and the normalized forecast RNG demand will be consistent with past ACPs and will be discussed further in Section 3.2 of this Executive Summary.
Forecast Annual Normal Demand for Rate Schedule 46 for 2025/2026 • FEI’s forecast demand for Rate Schedule 46 (RS 46) is 17 TJ/day for 2025/2026. Gas Procurement and Pricing Strategy • FEI recommends continuing with a balanced mix of daily and monthly priced commodity supply in the portfolio to provide operational flexibility and to help mitigate adverse price movements.
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FEI will continue to pursue contracting term purchases 13 based on securing a favourable basis between the Station 2 and AECO/NIT monthly price indices beyond the current gas year of 2025/2026 (up to three years out).
FEI recommends negotiating over a 10-month period from January 2026 to October 2026 for the 2026/2027 winter supply transactions at Station 2.
1 TJ is equivalent to 1,000 gigajoules (GJ). The anticipated amount of RNG is considered to be the volume that FEI expects an RNG plant to actually produce based on many factors including operational history, feedstock availability, system capacity constraints, operating limitations, and/or a forecast growth in volume over time. Term purchases or term supply is supply covering a winter, summer, annual or longer term as opposed to spot supply which is related to daily delivery only.
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FEI will continue to assess possibilities of pursuing long-term supply arrangements, up to 10 years in length, with BC gas producers to support long-term supply security at the Station 2 market.
Commodity Portfolio • The Daily Baseload Gas Supply from Commodity Providers will be 414 TJ/day, plus fuel. This takes into consideration that the normalized forecast demand for Core customers (436 TJ/day) is reduced by the normalized forecast demand amount of RNG (22 TJ/day).
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The receipt point allocation percentages for the Daily Baseload Gas Supply are to remain at the same levels as last year, which is 75 percent at Station 2 and 25 percent at AECO/NIT.
Commodity Providers’ fuel requirements for gas delivery on November 1, 2025, will be evaluated and communicated in September 2025. Commodity Providers’ fuel percentages are currently 4.5 percent at Station 2 and 1.3 percent at AECO/NIT for the period November 1, 2024, to October 31, 2025.
Midstream Portfolio • FEI will continue to try and retain the current level of seasonal and market area storage capacity. There could be a slight drop to FEI’s contracted capacity at Mist, as NW Natural continues to recall storage capacity for their customer load requirement.
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FEI will require seasonal and spot supply at Station 2, AECO/NIT, and East Kootenay. FEI will have pipeline capacity and call options available as contingency resources. FEI may purchase up to 50 TJ/day of spot or monthly supply at the Huntingdon/Sumas market, if required during a gas supply emergency.
FEI may purchase up to 10 TJ/day for operational support, on an as-needed basis.
2.2 Ongoing Portfolio Evaluation The recommended portfolio in the 2025/2026 ACP is intended to ensure that FEI is able to meet the needs of its Core customers on a peak day as well as under design and normal load requirements in a cost-effective manner. FEI will continue to evaluate new resource options as additional market information becomes known related to the availability and pricing of resource alternatives, basis differentials, and other relevant developments. Should any other significant variation from the proposed portfolio outlined in this ACP be needed, the requirements will be discussed with BCUC staff and an amendment subsequently filed with the BCUC for acceptance at an appropriate future date.
One of the more recent developments that FEI has been monitoring are the potential impacts to the gas supply portfolio due to US tariffs being imposed on Canadian products. There is a high
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degree of uncertainty surrounding these tariffs, with the most recent announcement (at the time of this filing) declaring no tariffs on Canadian energy (originally declared to be 10 percent). From FEI’s perspective, the majority of FEI’s gas supply procurement and purchasing strategies are on the Canadian side of the border, so any potential import tariff will not have a material effect on the supply portfolio. The only potential impact to the portfolio that FEI has identified and will monitor would be the natural gas supply associated with FEI’s market area storage at Jackson Prairie and Mist. However, the supply that may pass through the US would represent a small portion (~3 percent) of FEI’s total Core customer portfolio requirements. FEI will continue to monitor this development, but does not foresee any scenario in which tariffs would require FEI to make an adjustment to its 2025/2026 ACP.
Additional infrastructure in the region continues to be a major focus for FEI ongoing portfolio evaluation, especially in light of the growing demand in the region as well as for resiliency considerations. FEI is interested in a mix of infrastructure options that align with the same fundamental principles used in designing a cost-effective gas supply portfolio - matching the resource characteristics to the characteristics of demand. For example, FEI applied to the BCUC for a Certificate of Public Convenience and Necessity (CPCN) for the Tilbury Liquefied Natural Gas (LNG) Storage Expansion (TLSE Project) on December 29, 2020. The TLSE Project will significantly improve FEI’s ability to maintain continuity of service and avoid widespread and lengthy service outages in the period immediately following a severe supply constraint or a no-flow 14 event. It also provides gas supply benefits including the replacement of the aging Tilbury Base Plant 15 (particularly important as the loss of access to the Base Plant would jeopardize FEI’s ability to serve customers in normal operations), flexibility for gas supply planning, and support for future peaking load growth. On March 23, 2023, the BCUC identified additional analysis required before determining whether to grant a CPCN (Adjournment Decision). 16 On October 24, 2024, FEI filed additional evidence which included a significant amount of additional technical analysis with the assistance of external experts confirming that FEI customers will obtain the greatest value from a new facility with 800 MMcf/day of regasification and a 3 Bcf tank, as proposed in the application. Of importance to the ACP is the additional gas supply allocation (additional 0.4 Bcf of storage and 50 MMcf/day of deliverability) that would allow FEI to avoid significant gas supply costs by optimizing its gas portfolio. 17 The proceeding is still ongoing with the most updated development being round 6 of IRs sent to FEI on April 24, 2025. Responses are to be filed with the BCUC by May 22, 2025. If approved, the project development will take several years to complete.
As discussed in previous ACPs, FEI has been interested in securing long-term, non-recallable storage capacity which could only come through supporting an expansion to NW Natural’s North Mist storage facility (North Mist Expansion Project). FEI’s contracted capacity at Mist has several gas supply benefits to FEI, including its utilization to meet Core demand during colder than normal
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days of the winter. However, FEI’s contracted capacity at Mist does not have renewal rights, which is a risk to FEI’s security of supply. Moreover, NW Natural is expected to take back a significant portion of the storage capacity contracted to FEI for their customer load requirements once Woodfibre LNG project is in-service (as early as 2027), since the amount of demand from the Woodfibre LNG project will affect regional gas flows. This development is discussed further in Section 3 of the 2025/2026 ACP. To address this development and security of supply risk, FEI entered into a Precedent Agreement for Firm Interstate Storage Services which outlined the steps that NW Natural must take to finalize the North Mist Expansion Project, and the terms on which FEI will backstop the development of the project. The new deliverability from the North Mist Expansion Project will be able to replace the existing deliverability that FEI will lose beginning in 2027. FEI filed a confidential application to the BCUC to seek acceptance of the agreements with NW Natural related to the development of the North Mist Expansion Project, which was accepted on September 10, 2024. 18 Depending on the timeline of the Federal Energy Regulatory Commission (FERC) proceeding, the storage could be in-service by 2029.
An additional consideration that has been important to the ACP is future pipeline infrastructure projects which are typically brought forward through an “open season” where interested parties bid on the proposed expansion. Independent of FEI’s own needs, market conditions throughout region have driven the need for new pipeline infrastructure. Resource adequacy remains a significant concern, especially as the region continues to experience increasing use of natural gas for power generation, and the demand forecast for electricity is growing at a high rate within the Western United States. 19 Regional parties understand that the growing demand for power generation places additional stress on existing gas infrastructure, and discussions have begun for potential open seasons on Northwest Pipeline. FEI would be interested in additional regional pipeline infrastructure, including an expansion on Northwest Pipeline, but details of such expansion are still emerging. FEI has also long recognized that an expansion to FEI’s SCP, such as FEI’s Regional Gas Supply Diversity Project (RGSD Project), would help reduce FEI’s reliance on the T-South system, as well as alleviate the resource constraints that can occur in the winter during certain market conditions.
On April 30, 2024, FEI provided its Quarterly Progress Report (January 1, 2024, to March 31, 2024) on the RGSD Project to the BCUC, which reported on the conclusion of the RGSD Project development work and summarized key findings of the screening assessment. The preliminary results of this assessment indicate that the Oliver to Kingsvale pipeline routing option optimizes the use of existing regional infrastructure with potential lower costs and balanced risks, and is worthy of further assessment. This option requires co-commitments from Enbridge for the expansion from Kingsvale to Huntingdon and, considering its scale and magnitude, support from other market participants. Thus, commercial discussions are now required to explore ways to best integrate FEI’s existing pipeline infrastructure (SCP and existing 12” pipeline from Oliver to
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BCUC Decision and Order G-241-24. The 2024 Western Assessment of Resource Adequacy noted that the forecast rate of demand growth over the next decade is double what was forecast just two years ago. The Assessment can be found online at: https://feature.wecc.org/wara/.
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Kingsvale) with the Enbridge T-South system to create a new optimal regional infrastructure solution that can address current market conditions in the region.
There is a considerable amount of work that FEI is currently undertaking to address the considerations discussed above. The current number of infrastructure projects seeking regulatory approval or being proposed is unprecedented. Historically, pipeline expansions undergo an open season approximately every five years, and storage expansions tend to occur even less frequently. However, the region is at a critical point where multiple initiatives are under consideration simultaneously. There is uncertainty around when these projects will receive approval and, after approval, construction will take several years. This timing uncertainty presents a challenge for FEI in ensuring that it has enough secure and reliable resources in place each year to meet the peak day and design load requirements of its customers.
3 2025/2026 ACP This section provides an overview of significant topics that are discussed in detail in the 2025/2026 ACP, including the forecast design peak day and annual normal loads, changes in contracting for resources from the previous year, and operational and long-term planning considerations.
3.1 RS 1 to RS 7 Demand Forecast (Design Peak Day and Normal Load) The forecast design peak day demand for FEI’s natural gas service areas is 1,462 TJ/day for the 2025/2026 gas year, which represents a 10 TJ/day increase from the 2024/2025 gas year. Similarly, the winter design and the annual normal forecast for the 2025/2026 gas year increased compared to the 2024/2025 gas year by 12 TJ/day and 4 TJ/day, respectively. These increases were due to the colder than normal winters that FEI’s service areas have experienced in recent years and the continuing trend of transportation service customers returning back to FEI’s bundled service.
Table ES-1 sets out the forecast design peak day by region, the annual normal load requirements, as well as the design load requirements during the winter and summer season projected for the next five gas years. The peak day and winter load requirements are forecast to grow, which confirms the need for FEI to maintain access to its existing resources and evaluate future resource options should they become available.
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Table ES-1: Forecast Peak Day, Design and Normal Volumes by Region (RS 1-7)
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3.2 RNG Customer Supply Forecast The transition from conventional gas to renewable and low carbon gas continues to be an important component in the overall strategic planning of the ACPs. In May 2021, the provincial government issued an amendment to the Greenhouse Gas Reduction (Clean Energy) Regulation 20 (GGRR), which authorizes FEI to acquire hydrogen, synthesis gas, and lignin, in addition to RNG (which together FEI refers to as renewable and low carbon gas). The changes to the GGRR should help stimulate investment in and accelerate growth of renewable and low carbon gas supply and help enable FEI to achieve the Province’s emissions targets.
On October 25, 2021, the provincial government released the CleanBC Roadmap to 2030 (CleanBC Roadmap) as an update to the 2018 CleanBC Plan, which includes a proposed emissions cap applicable to natural gas utilities. As described in the CleanBC Roadmap, “the cap will be set at approximately 6 [megaton] Mt of [Carbon dioxide equivalent] CO2e per year for 2030, which is approximately 47 percent lower than 2007 levels.” 21 This proposed cap will require FEI to reduce GHG emissions by approximately 5.5 Mt of CO2e, which is equivalent to displacing approximately half of the conventional natural gas delivered to FEI’s distribution systems. This proposed emissions cap would be the first of its kind in Canada and would require FEI to invest in carbon saving technologies and solutions to displace conventional natural gas consumption by 2030. While legislation related to the CleanBC Roadmap’s planned cap on GHG emissions has not been enacted, legislation is in place targeting emissions reductions of 40 percent below 2007
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B.C. Reg. 134/2021. Government of BC, “CleanBC Roadmap to 2030,” (October 2021), p. 29.
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levels by 2030 22 ; therefore, FEI anticipates the need to acquire volumes of renewable and low carbon gas supply up to 15 percent by 2030.
The anticipated amount of RNG supply for the 2025/2026 gas year is approximately 33 TJ/day. The majority of the RNG supply is coming from off-system supply 23 and will be delivered at the Station 2 and AECO/NIT market hubs. Historically, FEI’s ACP strategy with its RNG supply has been to adjust its seasonal and spot supply purchases within the peak day portfolio (Table ES-2) to take into account the anticipated firm amount of RNG supply at the Station 2 and AECO/NIT markets. This strategy ensured FEI’s supply would not exceed its contracted amount of pipeline capacity on the Westcoast’s T-South and TC Energy’s NGTL and Foothills BC pipeline systems. This was also the most practical option as the RNG volumes were not material enough to make any major adjustments to FEI’s baseload supply requirements, nor did FEI have an established history with the level of RNG that had been forecast.
However, since July 2024, FEI has experienced a significant increase in its RNG supply which has been more aligned with the ACP forecast. Given this development, and as discussed in Section 1.3, FEI has now adjusted its normalized forecast demand for Core customers to take into account the normalized forecast demand amount of RNG to be delivered through the RNG Blend Service and the Voluntary RNG Service to Non-NGV Sales customers. 24 This has been done by reducing its 2025/2026 annual normal load forecast of 436 TJ/day (Table ES-1 above) by 22 TJ/day which is now the Daily Baseload Gas Supply requirement for Commodity Providers. The strategies deployed in past ACPs will be leveraged any time the RNG supply that FEI obtains on a daily basis is higher than the RNG demand (22 TJ/day) by adjusting the amount of conventional spot supply purchases made on the day as well as including the on-system 25 and off-system supply delivered at the Huntingdon/Sumas market to supplement FEI’s contingency resource requirements.
While FEI anticipates that RNG will continue to make up most of the renewable and low carbon gas supply during the 5-year planning horizon, FEI is undertaking work to advance hydrogen supply and delivery. This work includes progressing feasibility and readiness assessments, exploring hydrogen blending pilots and industrial gas displacement, and investigating pathways to support technical and commercial development of low carbon hydrogen supply. Consistent with past ACPs, FEI will develop and monitor any long-term plans with respect to renewable and low carbon gas supply and its impact on future ACPs.
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Climate Change Accountability Act, S.B.C. 2007, c. 42, s. 2. The off-system supply is the supply that is injected into another natural gas system, typically out-of-province, displacing an equal unit of conventional natural gas, and delivered to FEI at a delivery point. RNG Blend, Storage and Transportation RNG Rider, RNG Charges, and 2024 Q4 Gas Cost Report for the Mainland and Vancouver Island, and the Fort Nelson Service Areas Effective January 1, 2025. This was filed to the BCUC on November 18, 2024 and approved via Order G-325-24A on December 5, 2024. The on-system supply is the supply injected directly onto the FEI system.
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3.3 RS 46 Customer Supply and Demand Forecast Consistent with past ACPs, FEI is focused on how to meet RS 46’s operational demand (i.e., liquefaction runs at FEI’s Tilbury LNG facility) and not the customer demand. FEI continues to hold 35 TJ/day of T-South Huntingdon Delivery 26 capacity to meet Tilbury 1A’s operational requirement of liquefaction rates. FEI will purchase a portion of Station 2 term supply to fill this T-South pipeline capacity for the winter period (November to March). This avoids potential supply and/or pricing risks that may arise should FEI decide to purchase all of the supply in the spot market.
3.4 The 2025/2026 Portfolio Table ES-2 sets out a summary of the portfolio planned for the 2025/2026 gas year. After evaluation of the new peak, design and normal day load forecasts, current portfolio mix, and market developments, FEI recommends the following resource portfolio for the 2025/2026 gas year:
Table ES-2: Planned Peak Day Portfolio - 2025/2026 Compared to 2024/2025
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Huntingdon Delivery Area is defined in Westcoast’s General Terms and Conditions as the area comprised of the Export Delivery Area and the Lower Mainland Delivery Area.
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3.4.1 Fort Nelson Service Area FEI’s total pool of gas supply resources are used as required to manage the total daily load for all of FEI’s service areas, which includes the load of the Fort Nelson Service Area. The forecast average daily supply requirement for the Fort Nelson Service Area is 1.3 TJ/day and the forecast peak day load is 5 TJ/day. Historically, FEI has served the Town of Fort Nelson by purchasing the commodity supply at the outlet of the Fort Nelson gas plant from a producer and then moving the gas using its contracted capacity on the Westcoast T-North system (i.e., T-North Short Haul service). On June 3, 2024, NorthRiver Midstream announced the suspension of operations at its Fort Nelson gas plant due to the wildfires that were occurring at the time, but also due to the other challenges the plant has faced, specifically the reduction in gas supply coming out of the plant over the past several years. 27
At this time, FEI believes the most viable option is to use the Westcoast system to back-flow supply north to the Fort Nelson Service Area. This option has been in place since the announcement to suspend operations at the Fort Nelson gas plant and performed well through the past 2024/2025 winter season. On March 31, 2025, Westcoast filed a letter with the CER, which included its confidential third-party engineering assessment of its Fort Nelson Mainline. 28 Westcoast’s letter states that the engineering assessment confirmed the continued viability of providing bidirectional service on the Fort Nelson Mainline using linepack supply. As a result, for the upcoming gas year, FEI will continue to use its Station 2 supply (spot and/or seasonal) to back-flow north to the Fort Nelson Service Area. The engineering assessment also confirmed that beyond 2026, to maintain fitness for service until at least the end of 2030, the Westcoast needs to undertake integrity maintenance. FEI will continue to monitor this development and will provide the BCUC with any necessary updates.
3.4.2 Winter Period Priority Schedule and Daily Resource Optimization For each winter month, FEI Midstream generates a priority schedule of all contracted resources that are ordered by contract type. The purpose of this schedule is to ensure that these resources will be used when required or mitigated as best as possible when they are not needed, as part of an overall plan to efficiently manage them on the day. Supply with 100 percent load factor is drawn first, with more flexible resources, such as storage, placed further up the supply stack.
To determine how to best manage the resources in the portfolio for any given day, FEI receives a forecast every morning of the system load for each of the next five days that it compares against its supply stack of 100 percent load factor resources and seasonal storage. If more supply is available than required to meet the forecast load, FEI will resell the excess baseload or seasonal gas at the location resulting in the highest margin, or inject gas into storage, particularly if market area storage such as Jackson Prairie and Mist storage requires refilling or topping up. If spot market prices are considerably lower than the forward market, FEI may elect to not resell on the
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NorthRiver Midstream (June 3, 2024). “News Release.” NorthRiver Midstream regretfully suspends Fort Nelson gas processing facility operations – NorthRiver Midstream (nrm.ca). Westcoast Condition 4 compliance filing with the CER - C34000-1_Letter_-_A9H9F2.pdf.
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day market and reduce its withdrawal of seasonal storage, or inject term gas into shorter duration market area storage for refilling to help maintain deliverability.
If Core customer demand exceeds the combination of term commodity and seasonal storage contracts, FEI will evaluate other storage and peaking resources that could be utilized to meet the daily requirement.
3.5 Commodity and Midstream Portfolios Commodity Providers, including FEI Commodity and Gas Marketers, are responsible for delivering the Daily Baseload Gas Supply. FEI Midstream is then responsible for managing this daily supply. It provides daily load balancing services that include optimizing seasonal and peaking gas supply, utilizing storage and pipeline capacity necessary to meet the peak day demand, and managing any variability in demand.
FEI must be prepared to meet a peak day as well as winter design and normal load forecasts for the year commencing November 1, 2025 and ending October 31, 2026. Moreover, FEI contracts for diverse and flexible resources to manage load swings during spells of colder or warmer than normal weather and to mitigate interruptions in delivery capacity related to both transportation and storage.
3.5.1 Gas Procurement & Pricing Strategy The procurement and pricing strategy for FEI’s portfolio includes a combination of monthly and daily priced supply for price diversification. Having a diversity of monthly and daily priced gas in the portfolio provides flexibility around the resale of excess gas that arises from the inevitable variances between actual and forecasted volumes. Daily priced supply can be resold in the market at the same price as it is bought, therefore removing any price exposure of surplus resources when compared to monthly priced supply. This strategy helps FEI to remain cost neutral when reselling gas on the day. Monthly priced supply helps reduce exposure to market price volatility during the winter months and provides FEI with flexibility to implement hedges if warranted in the future.
FEI takes a longer-term outlook when contracting for some resources, like transportation and storage assets, and may be restricted to some degree in changing these resources in the portfolio in a particular year. However, customers realize the benefit of these resources because they provide security of supply and increased portfolio diversity. Gas supply from various storage facilities in the winter provides the portfolio with diversity and intraday flexibility, as well as lower cost summer-priced supply.
3.5.1.1 FEI’s Station 2 Procurement and Pricing Strategy FEI’s management of Station 2 supply is dependent upon its Westcoast T-South capacity holdings. Given the significant amount of T-South capacity that FEI contracts to manage winter
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load requirements, FEI’s supply at Station 2 varies between long-term supply arrangements, term and spot purchases.
The Station 2 market is illiquid compared to its regional counterpart at AECO/NIT, due to its smaller market size (Station 2 physically delivers approximately 2 Bcf/day compared to approximately 12 Bcf/day 29 at AECO/NIT) and lower number of participants (suppliers and end users). These factors translate into a lower amount of term supply being transacted at Station 2 compared to AECO/NIT.
This illiquidity has presented challenges for FEI, as it can affect pricing and security of supply under certain market conditions. To alleviate this challenge, FEI has implemented strategies including transacting purchases (seasonal and annual) at Station 2 for terms outside the gas year and securing long-term supply agreements at Station 2. These supply arrangements help FEI manage the changing market conditions and continue to provide pricing diversity to the portfolio, while also providing regional gas producers much needed alternatives. Offering these types of arrangements as well as providing flexibility in the pricing arrangements has proven to be vital for FEI to maintain and establish relationships with the producers who continue to develop supply in BC.
3.5.2 Issues Affecting Supply and Capacity Planning Consistent with FEI’s past ACPs, constrained pipeline and storage resources during the winter season continues to be a major concern. Over the past several years, market conditions have caused increased supply and pricing risks in the region. The following two subsections describe the two major issues that can affect the planning portfolio (gas supply resiliency risks and customer movement between bundled and transportation service models), and how FEI will mitigate these risks in the short-term.
3.5.2.1 Gas Supply Resiliency Risks While FEI has long regarded resiliency as an important system attribute, the T-South Incident, which occurred on October 9, 2018, brought into focus the risk of supply interruption for FEI’s Lower Mainland customers. FEI obtains most of its natural gas via the Westcoast T-South system, making a disruption on the T-South system the greatest supply risk facing FEI at present. A sudden, prolonged, and wide-scale gas supply interruption could directly or indirectly affect the livelihood, health, and safety of virtually every resident of the Lower Mainland, regardless of whether they are a customer of FEI or not.
Over the past several years, FEI has, to a degree, increased resiliency within the portfolio by holding contingency resources on T-South and by taking back capacity on the SCP. However,
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An increasing portion of BC produced gas, specifically from the Montney supply basin, is flowing to the AECO/NIT marketplace.
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FEI has few options to further increase resiliency in the short term given that resources in the region are fully contracted and can be constrained during the winter.
Since 2019, FEI has maintained contingency resources within the ACP portfolio and FEI plans to continue this practice for the foreseeable future. Contingency resources are resources (e.g., supply, LNG, and pipeline infrastructure) above the current load forecast for Core customers that can be called on if planned resources are unexpectedly not available or insufficient to meet demand. The contingency resources also help manage sustained increases in demand during extended periods of cold weather.
FEI determined that a planning margin of approximately 15 percent was reasonable, taking into consideration what occurred during the T-South Incident and, specifically, the resulting capacity impacts of the CER’s orders to reduce operating pressure on the T-South system. 30 This planning margin will likely remain in effect until there is a new pipeline that follows a different path than what is available today.
3.5.2.2 Customer Movement Between Bundled and Transportation Service Models
Historically, customer movement between FEI’s bundled service 31 and the transportation service 32 has been relatively minor. Many of the transportation service customers in the Lower Mainland have been able to serve their demand requirements by accessing some transportation capacity in the secondary market 33 and by purchasing gas supply at the Huntingdon/Sumas market. FEI became concerned when large-scale industrial projects proposed in the region, specifically Woodfibre LNG, began securing firm transportation capacity on the Westcoast T-South pipeline for a portion, if not all, of their supply requirements. The concern was that the incremental demand from these projects could pose a risk to any customer that relies on supply at the Huntingdon/Sumas market.
FEI first became concerned with these regional transportation and storage resources constraints in 2014 and secured additional T-South capacity to allow for the potential of transportation service customers returning to bundled service, as well as for future load growth. 34 This proved to be a prudent decision because the T-South Huntingdon Delivery capacity has been fully contracted since that time. FEI began to experience an increase in transportation service customers moving back to the bundled service in 2017, but the most significant movement occurred after the T-South Incident, when 42 percent (over 900 transportation service customers)
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See: Canada Energy Regulator, Oversight of Pipeline Incidents, (Archived February 2, 2023) online at: https://www.cer-rec.gc.ca/en/safety-environment/compliance-enforcement/cer-oversight-recent-incidents/archives/index.html. Bundled service means that a customer purchases both the gas supply and delivery service from FEI. FEI’s Core customers take bundled service. Customers who elect to take service under the transportation service model arrange for their own supply that is then transported by FEI to their premises. Shippers on the T-South system can temporarily release pipeline capacity on an annual or seasonal basis that is not required for their own use. Approved by the BCUC on December 3, 2015 by Letter L-43-15.
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provided notice to FEI of their intention 35 to return to bundled service as of November 1, 2019. Given FEI’s proactive decision to secure additional T-South capacity for this potential development, the customer movement after the T-South Incident did not have a material impact on the portfolio.
The volatility at the Huntingdon/Sumas market continued after the T-South Incident, which has led to more transportation service customers returning to the bundled service. This was exemplified during the 2022/2023 winter season, when the Huntingdon/Sumas market experienced greater pricing volatility than what occurred during the T-South Incident, as Figure ES-2 illustrates below. The average Sumas daily price between November and March was approximately $16/GJ, which was over $12/GJ higher than the Station 2 price and over $15/GJ higher than the AECO/NIT price. This development led to over 230 transportation service customers providing FEI their notice to return to the bundled service effective November 1, 2023.
Figure ES-2: Station 2, AECO/NIT and Sumas Daily Spot Prices (2011 to 2025)
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This was due to the volatility at the Huntingdon/Sumas market when the average Sumas daily price for the entire 2018/19 winter was approximately $15 Cdn/GJ, which was approximately $12 Cdn/GJ higher than FEI’s cost of gas.
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This development has had a significant impact on the ACP, as the winter design load forecast has increased by ~100 TJ/day since the 2017/2018 gas year. This customer movement poses risks to FEI’s gas supply portfolio, such as not being able to secure enough incremental resources in the region to serve more transportation service customers moving to FEI’s bundled service. FEI has offset these increases by utilizing its supplemental pipeline capacity held on T-South (i.e., contingency resources). However, this comes at the expense of having less T-South capacity to help meet FEI’s 15 percent planning margin for resiliency purposes, which exposes its Core customers to more risk of supply disruption. Given that FEI’s excess pipeline capacity that has been serving as a contingency resource is declining, further demand increases from Core customers and/or a reduction of non-renewable resources (i.e., Mist storage capacity and deliverability) will result in having portfolio exposure to the Huntingdon/Sumas market until new infrastructure in the region is added. This is discussed in detail throughout the 2025/2026 ACP.
3.5.3 Commodity Portfolio Overview: 2025/2026 Commodity Providers provide the Daily Baseload Gas Supply of 414 TJ/day, plus fuel, to FEI Midstream effective November 1, 2025. The receipt point allocation percentages for the Daily Baseload Gas Supply for the 2025/2026 gas year continue to be 75 percent at Station 2 and 25 percent at AECO/NIT.
Gas Marketers participating in the Customer Choice Program are responsible for ensuring a portion of the Daily Baseload Gas Supply is delivered to FEI Midstream at each of the receipt points. For the 2025/2026 gas year, the average daily volume that will need to be provided by Gas Marketers is approximately 20 TJ/day, while 394 TJ/day will be provided by FEI Commodity.
Table ES-3 shows the estimated Customer Choice marketer volumes and enrolments for 2025/2026 compared to the estimates provided in the 2024/2025 ACP.
Table ES-3: Year over Year Change in the Estimated Customer Choice Marketer Volumes and Enrolments 36
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This estimate is based on actual and forecast enrolments in the Customer Choice Program taken in March 2024 (for the 2024/2025 forecast) and March 2025 (for the 2025/2026 forecast).
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Based on the current BCUC-approved 37 receipt point fuel gas percentages, FEI Commodity is required to provide the following amounts at the specified delivery points starting November 1, 2025:
Station 2: (414 TJ/day – 20 TJ/day) x 75% plus 4.5% fuel = 309 TJ/d
AECO/NIT: (414 TJ/day – 20 TJ/day) x 25% plus 1.3% fuel = 100 TJ/d
The BCUC reviews the fuel gas balances and the receipt point fuel gas percentages on an annual basis. FEI submits a report by September 1 of each year on the actual and forecast fuel gas consumption and collection; the report also includes any request for changes to the receipt point fuel gas percentages for the upcoming gas year. 38
3.5.4 FEI Midstream Portfolio Overview: 2025/2026 FEI Midstream manages supply to meet the variability in customer demand, including the peak day demand, as well as daily fluctuations with RNG supply. It does this by providing seasonal and peaking commodity, storage services, and the transportation capacity necessary to manage supply/demand imbalance.
FEI Midstream’s annual evaluation of its portfolio considers critical factors such as security of supply, reliability, delivered cost of supply, and availability of alternative incremental resources. To replace expiring resources and/or meet future growth requirements, FEI Midstream assessed several alternatives for 2025/2026:
• • • • • •
Station 2 supply and associated T-South Huntingdon Delivery capacity; Alberta supply with associated firm transportation capacity; East Kootenay spot and peaking supply; Additional supply for contingency resources, emergency and/or operational purposes; Seasonal storage (Aitken Creek and Rockpoint); and Market area storage (Jackson Prairie and Mist).
Additionally, FEI has on-system gas supply from resources such as the Tilbury and Mt. Hayes LNG storage facilities that can provide high volume supply on a short-term basis during periods of cold and extreme winter weather or emergency situations.
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BCUC Order G-245-24, effective November 1, 2024. Pursuant to BCUC Letter L-49-08.
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A review of the storage and third-party transportation agreements that have been or will be negotiated are outlined in greater detail within the confidential sections of the 2025/2026 ACP. This also applies to the contracting strategies at the Station 2, AECO/NIT, Huntingdon/Sumas, and East Kootenay markets.
3.6 Regional Dynamics Impacting Portfolio Development for Future ACPs FEI continues to evaluate its portfolio over a five-year period. This approach is appropriate as regional dynamics can change the value and availability of existing resources, as well as create opportunities for FEI to optimize the portfolio in the interests of meeting the objectives of the ACP. A five-year period is also important given that certain market conditions could impact future resources available to FEI.
At a high level, FEI will monitor the following six market conditions for the 2025/2026 gas year and beyond:
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1. Woodfibre LNG has secured firm transportation capacity on the T-South system for a significant portion of their demand requirements. Once this project is in-service, the regional gas flow and prices for all customers may be impacted.
2. The demand forecast is increasing within FEI’s natural gas service areas and within regional local distributions utilities service areas Pacific Northwest. 39 The load profile of the demand is also changing, specifically due to the gas power generation in the region, as curtailable load continues to decline (Figure ES-3 below). This has put a strain not only on peaking resources, but on baseload and storage resources during the winter period.
Northwest Gas Association (2024). “2024 Pacific Northwest Gas Market Outlook.”
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Figure ES-3: Natural Gas for Power Generation on Northwest Pipeline (Winter Averages)
3. Customers are moving from FEI’s transportation service model to the bundled service due to the volatility of the Huntingdon/Sumas market and security of supply issues.
4. There is a risk of FEI’s shorter duration market area storage capacity, specifically at Mist, being recalled over the planning horizon.
5. The next major pipeline expansion in the region could face lengthy delays, given the greater number of uncertainties now tied to large-scale pipeline expansions.
6. Future disruptions to third-party pipelines and storage facilities that FEI accesses supply from can pose a serious risk to the security of supply and the resiliency of its system. Given that resources in the region are limited, FEI’s portfolio requires an evolving strategy to mitigate this risk.
On a planning basis, FEI has held excess resources in the ACP portfolio since contracting additional T-South Huntingdon Delivery capacity in October 2014, when the first market factor discussed above became apparent. Since then, FEI has observed the other market factors discussed above, which place even more value on existing resources in the region.
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FEI monitors the daily demand from the natural gas-fired generators that are directly tied to Northwest Pipeline, which is illustrated in Figure ES-3. Historically, the generators would only run on colder-than-normal days during the winter and had the ability to shut off if necessary. This practice has fundamentally changed. As illustrated in Figure ES-3, for the past three winter seasons, demand from these natural gas-fired generators averaged 175 MMcf/day higher than the five-year average between 2017 and 2021, and they operated at or near maximum capacity on a daily basis throughout the entire winter period.
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FEI continues to hold more resources than the Core customers require within its portfolio of resources; however, given the significant load growth over the past five years, that amount has been declining. FEI’s ability to contract for additional firm (pipeline and storage) resources is limited given that the resources are fully contracted. Therefore, if FEI’s load continues to increase and/or existing market area storage resources are recalled, FEI will likely require short-term alternative supply arrangements (i.e., secondary market offerings likely tied to a Sumas price) within the 5-year planning horizon. FEI does not want to expose its Core customers to the price and volatility risk associated with the Huntingdon/Sumas market in order to meet their firm demand, and therefore fully supports additional infrastructure in the region, which is discussed further in 2025/2026 ACP.
If FEI’s Core load requirements decline year-over-year and/or market developments proceed at a pace that do not result in any incremental demand, FEI’s gas supply portfolio provides the flexibility either to allow contracts to expire without renewal, release to a third party, or to decrease contracted amounts when they are up for renewal.
4 CONCLUSION FEI’s 2025/2026 ACP has been developed to meet the objectives set out in Section 1 of this Executive Summary. The ACP reflects an appropriate balance of commodity, storage, and transportation resources required to meet the forecast demand from all of FEI’s natural gas service areas. FEI recommends continuing with a balanced mix of monthly and daily priced commodity supply in the portfolio, supported by a range of storage and transportation options. This mix provides the resource flexibility required to reliably serve customers across a large, geographically diverse area, to manage load variability throughout the year, and to help mitigate adverse price movements. FEI also continues to develop and monitor any long-term plans with respect to renewable and low carbon gas and its impact on future ACPs.
Supply and demand developments in the region, including increasing regional demand, risks of disruptions to infrastructure, and increasing use of natural gas for power generation are creating uncertainty in the marketplace. Existing storage and pipeline resources are constrained, causing higher value during the winter season, especially for T-South capacity to Huntingdon. Given these market conditions, FEI continues to hold supplementary pipeline capacity on T-South as a contingency resource within its portfolio of resources. This approach is reasonable because the costs and ability to manage pipeline capacity renewals within the portfolio helps to reduce the risk to Core customers. However, this strategy will be difficult to continue in the near future as FEI’s supplementary pipeline capacity has already been declining due to the significant load growth over the past several years and FEI’s contracted capacity at Mist is at risk of being significantly reduced. FEI continues to explore additional options using the existing resources in the region; however, as outlined in Section 4 of the confidential 2025/2026 ACP, those available options are either limited or come with high costs.
Given these developments, it is important for FEI to continue renewing all its existing gas supply contracts if possible, and to identify, investigate, and support appropriate infrastructure solutions that will help maintain the reliability of gas flows while creating options and flexibility for FEI’s
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portfolio over time. This includes ongoing support of NW Natural’s North Mist Expansion Project as well as continuing to move the TLSE project forward and exploring commercial discussions for additional regional pipeline solutions.
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