Power Perspectives: British Columbia Regional Overview

This article originally appeared as a chapter in our Power Perspectives 2025 publication and provides a look back at some of the key developments in the British Columbia power market occurring in 2024. Power Perspectives 2025 provides an in-depth overview of the most significant developments in the Canadian power and emerging energy sectors in 2025.

Updates have been included in this version of the British Columbia Regional Overview to reflect certain recent developments in 2025.

Introduction

In 2024, a significant response to BC Hydro and Power Authority's ("BC Hydro's") April 2024 call for power ("Power Call"), along with the advancement of a number of decarbonization initiatives in the province of British Columbia, signalled a bright future for clean energy production in British Columbia. Through the Power Call process, BC Hydro positioned itself to integrate more wind and solar energy into the grid by as early as 2028. In 2024, we also saw the utility continue its EPA Renewal Program, while several liquid natural gas projects in British Columbia achieved significant milestones and the long-awaited Site C hydroelectric project further progressed towards its operational date.

BC Hydro's Call for Power

On April 3, 2024, BC Hydro issued the Power Call, its first competitive call for power in 15 years. The Power Call aimed to acquire approximately 3,000 gigawatt hours per year ("GWh/y") of renewable, emission-free electricity that could be on-line as early as the fall of 2028. The Power Call targeted an addition of 5% to the current energy supply – enough to power 270,000 homes or one million electric vehicles per year.

In 2022, BC Hydro identified the need to prepare for a significant power procurement in response to developments identified in the 2021 Integrated Resource Plan ("2021 IRP") Signpost Update (see Power Perspectives 2024 for more information). The Signpost Update, among other things, confirmed the need for new sources of power in the province sooner than what was expected in the 2021 IRP. While BC Hydro's energy forecasts in 2021 anticipated an energy surplus of 500 GWh, the 2023 updates anticipated an energy deficit of 3,500 GWh by 2030 with electricity demand projected to rise 15% over the same period.

Engagement Sessions

After announcing the Power Call in June 2023, BC Hydro began an extensive engagement and consultation process, hosting information sessions, workshops, technical sessions and consultations with independent power producers ("IPPs") and First Nations. Between June 2023 and the end of the engagement phase in January 2024, BC Hydro engaged 99 First Nations, hosted 31 information sessions, focus groups and engagement sessions, and received over 2,500 individual pieces of feedback. The findings from the engagement sessions were used to update the draft Request for Proposals ("Draft RFP"), circulated in 2023.

Response to RFP

The Power Call received a strong response. By the submission deadline of September 16, 2024, BC Hydro received 21 proposals from across British Columbia. In total, the proposals amounted to more than 9,000 GWh/y – more than three times BC Hydro's target and enough to power approximately 800,000 homes.

The proposals primarily consisted of wind energy projects (70%), followed by solar (20%), and a combination of biomass and hydro (10%). The proposals represented a broad geographic distribution, spanning various regions of the province, including the Southern Interior, Central Interior, North Coast, Peace Region and Vancouver Island. Such varied locations could boost regional economic growth and diversify energy sources in British Columbia. The variety of participants is illustrative of a province-wide interest in developing clean, renewable energy projects with a focus on wind and solar power.

Proposal Assessment

BC Hydro assessed the proposals based on the criteria outlined in its revised Request for Proposals. First, projects were evaluated for eligibility. Then, the assessment was a qualitative and quantitative exercise.

Eligibility

To participate in the Power Call, projects are required to be located in British Columbia (excluding Fort Nelson and other areas not integrated with BC Hydro), connect or deliver to BC Hydro's integrated system without passing through another jurisdiction, and be a new facility, although expansions to existing facilities that consist of new generating units are also eligible. Each eligible project also needed to qualify as a clean or renewable resource as defined in the Clean Energy Act (British Columbia) ("CEA"), which includes wind, solar, hydro, biomass and geothermal heat. Projects must also use proven generation techniques and have an executed Competitive Electricity Acquisition Process IR filed with BC Hydro.

BC Hydro emphasized cost-efficiency by seeking larger projects that benefit from economies of scale and that can be constructed and brought online quickly. Projects must demonstrate a proven resource capable of producing between 40 and 200 megawatts ("MWs") and achieve commercial operation between October 1, 2028, and October 1, 2031.

Projects are also required to comply with the requirements for First Nations equity ownership, with a minimum of 25% Indigenous equity ownership in the entity owning and controlling the generating assets (which must be held by one or more Indigenous groups in whose territory the project is located). Proposals that do not provide confirmation of a minimum 25% First Nations equity ownership will be disqualified from the Power Call (see below for more detail).

Qualitative and Quantitative Assessment

After satisfying the eligibility requirements, BC Hydro also conducted a quantitative assessment of the proposals using evaluation adjusters which were then applied to the bid price. An evaluation price was determined by converting the bid price in the proposal to a levelized-real bid price of equal value. Then, the levelized-real bid price is adjusted to account for project attributes. The evaluation price was solely used for the proposal assessment phase, and is not the amount that will be paid for energy under the energy purchase agreement ("EPA").

BC Hydro also reviewed the First Nations Consultation and Economic Participation materials to determine if the proponents had adequately consulted with First Nations. This requirement was added in 2024 having been absent from the Draft RFP published in 2023. Proponents were required to have consulted comprehensively with First Nations potentially affected by their proposed project, detailing their engagement efforts, methodologies for identifying the relevant groups and the chronology of consultations. BC Hydro evaluated these efforts based on several criteria, including the impact on Aboriginal rights and the effectiveness of communication. Proponents provided documentation, such as communication records, shared information and agreements, to substantiate their consultation activities.

BC Hydro also had the discretion to consider broader factors, including:

• the proposal's impact on the interconnection, transmission, and generation infrastructure
• how the proposal fits with BC Hydro's current load/resource balance;
• the environmental implications of the project;
• the proposal's alignment with BC Hydro's strategic goals;
• the long-term and annual costs associated with the proposal;
• the balance between commercial and non-commercial trade-offs, including the security of electricity supply and market competitiveness; and
• other public interest factors, especially those affecting ratepayers.

BC Hydro had the discretion to conduct reference checks, background investigations, and could request additional information, interviews or presentations to clarify and validate submissions. Proposals could be rejected for various reasons including lack of clarity, inadequate commercial terms, insufficient qualifications or non-compliance with evaluation criteria. BC Hydro was also willing to dismiss proposals due to financial instability, safety concerns or cybersecurity issues.

First Nations Participation

As part of BC Hydro's commitment to economic reconciliation, it collaborated with First Nation groups in designing the Power Call and the specimen electricity purchase agreement. Under the Power Call, the First Nations economic participation model consists of three components:

1. As noted above, a minimum 25% First Nations equity ownership in each project, assessed on a pass/fail basis. Such minimum First Nations equity ownership must be maintained until the third anniversary of the project's commercial operation date. If the proponent cannot certify at the commercial operation date (:COD:") of the project and on each of the first three anniversaries of COD, that the requisite level of First Nations equity ownership has been maintained, the energy price will be reduced by 5% for deliveries in the subsequent year or the EPA could be terminated.
2. Evaluation credits to acknowledge First Nations equity ownership in excess of the minimum 25% First Nations equity ownership, up to 51%. In particular, more credit will be given for 49, 50 or 51% First Nations equity ownership than for a 26–48% equity interest.
3. Non-equity economic benefits accruing to non-equity owner First Nations under a proposal. Non-equity benefits may include royalties, jobs, training, procurement and other investments in non-equity First Nation communities. This credit is designed to spread benefits across First Nation communities.

In addition to funding opportunities made available by the Canada Infrastructure Bank, proponents have access to the First Nations Equity Financing Framework, which was launched by the British Columbia government ("Government") in February 2024. The framework includes a special account with an inaugural balance of C$10 million to support immediate capacity funding needs for First Nations considering equity participation in priority projects. The account will have a cumulative loan guarantee of C$1 billion and will be reviewed annually. See the Financing section of this chapter for further discussion of government and BC Hydro funding programs.

Looking Forward

In December 2024, BC Hydro selected 10 energy projects from the Power Call, and the successful proponents and First Nations partners are set out below:

10 Energy Projects

Successful proponents were required to execute the EPA (and related side letter) no later than 10 business days after receiving the EPA from BC Hydro. Condensed timelines and other unique features of the Power Call, including the significant commercial involvement of First Nations as true risk sharing partners, intensified the challenges for potential proponents (see also Considerations for Wind Power Projects below).

The development and construction of these new clean-energy projects are anticipated to inject between C$2.3 billion to C$3.6 billion in private capital spending throughout British Columbia, creating an average of 800 to 1,500 jobs annually. BC Hydro's strategic calls for power, coupled with the initiatives proposed in the province's Capital Plan (as hereinafter defined), are projected to stimulate around C$40 billion in public and private capital investments, creating an estimated 11,300 to 14,000 construction jobs in total each year.

On April 30, 2025, the province introduced Bill 14 – 2025 Renewable Energy Projects (Streamlined Permitting) Act, which seeks to streamline permitting processes for renewable energy projects, including the Power Call projects. If passed, Bill 14 will expand the authority of the BC Energy Regulator ("BCER") to oversee renewable energy projects, exempt the Power Call projects from the environmental assessment process under the Environmental Assessment Act (and allow government to do the same for wind power projects in the future), and enable the BCER to establish a new regulatory review framework for renewable energy projects through consultation with First Nations.

As a function of its "Powering Our Future: BC's Clean Energy Strategy," the province has committed to routine, competitive calls for power ensuring the province meets its clean electricity requirements while the economy and population grow. BC Hydro expects a rise in power demand in the coming years, and on May 5, 2025 announced its next 2025 Call for Power, under which it expects to award EPAs in early 2026.

10-year Capital Plan

In January 2024, BC Hydro released its 10-Year Capital Plan, called the Power Pathway: Building B.C.'s Energy Future ("Capital Plan") The Capital Plan includes C$36 billion in investments for regional and community infrastructure across British Columbia – a 50% increase from the previous plan. This Capital Plan not only aims to enhance electricity generation but also focuses on expanding and strengthening the transmission and distribution system. It is designed to efficiently deliver clean power to new residential, commercial and industrial developments as required.

Nearly C$10 billion will be directed towards new electrification and gas reduction efforts, while C$21 billion will be allocated to improving system assets. The remaining C$5 billion will be used to connect new customers, particularly in high-growth areas across the province.

With a surge in population, and with it residential, commercial and industrial electrification, energy demands are soaring. To address this, approximately C$2 billion is being invested in various projects in the Lower Mainland and Vancouver Island, including the construction of new substations and the expansion of existing ones, alongside enhancements to the transmission lines and distribution network. These construction projects are projected to create an annual average of 10,500 to 12,500 jobs and will maintain BC Hydro's capital investments at a substantial level, particularly as major projects like Site C reach completion in 2025.

Considerations for Wind Power Projects

In the Power Call, nine out of 10 of the projects awarded EPAs (over 1,500 MW in total) were wind farms. Historically dominated by hydroelectricity, with a legacy of large storage-hydroelectric assets forming its backbone, the province's electric grid contains strong fundamentals to support the growth of wind energy. However, the grid-scale uptake of wind electricity in a province with low current utilization of such technologies engages certain legal and policy considerations around system-level management.

As wind electricity generation is intermittent, it cannot be relied upon to provide firm base load at any given time. Large sources of firm energy, such as storage hydro projects with large reservoirs that can be drawn upon as needed, are critical to supporting a diversified mix of renewable energy sources. As the province electrifies and the population and economy continue to grow, however, increased demands are being placed upon the historical network of hydroelectric facilities at the same time that climate change is impacting the reliability of British Columbia's water system. Thus, with significant growth of wind energy generation in the province, there will be new pressures on the grid to match supply with demand in real time and to optimize energy flows to reduce waste. A strong and stable grid with redundant capacity and intelligent design is needed, and utility-scale battery storage will be a key element of grid flexibility. In theirlatest integrated resource plan, BC Hydro has stated a need to add up to 600 MW of battery storage capacity to the provincial grid by 2030, roughly equivalent to 5% of BC Hydro's entire generation capacity, signaling an evolution of their conception of the grid and a likelihood of future storage solutions to be pursued into the decades ahead. Further investments in smart grid technology, including in the areas of dispatch management and controls, are expected as BC Hydro engages in iterative resource planning. This will nurture a currently nascent market in the province for providers of such services and technologies, leading to new procurement processes, capital demands and regulations. With the wide array of provincial energy objectives set out in the CEA, these markets are likely to develop in the unique British Columbian context and navigating them will require robust understanding of local market and policy forces.

Increased battery storage also engages the issue of systematic energy loss, as energy generated at a wind farm and stored in a battery will be diminished both during the transmission to and from the battery facility, and when the energy is converted from electrical to chemical form and back to electrical again as it passes in to and out of the battery units. Similar limitations beset pumped storage hydro (for which British Columbia has over 80% of all of Canada's potential capacity), where surplus electrical energy is converted into mechanical energy to pump water up a gradient so it can be infused with potential energy to subsequently be converted back into electrical energy by running it downhill through a turbine.

Given BC Hydro's statutory mandate to ensure its electricity rates remain "among the most competitive in North America," additional costs from energy loss due to storage will need to be borne by either generators or BC Hydro itself without being passed on to consumers. The broad and tight regulation of BC Hydro's capital, revenues and expenditures by the British Columbia Utilities Commission ("BCUC") will likely ultimately require BC Hydro to pass these additional costs to generators either in the form of lower electricity prices or in less favourable legal and commercial terms. There were some early doubts about the attractiveness of the terms offered under the Power Call. In particular, the large potential exposures for developers in the form of liquidated damages and other mark to market risks under the EPA that indicate BC Hydro's willingness to allocate risks to generators in service of policy objectives are speculated to have had a cooling effect for some potential participants in the Power Call. Revisions to the specimen EPA in subsequent calls for power will closely watched.

In addition to more storage and better management of electricity flows, expanded transmission capacity is needed to service the increased demands of a rapidly electrifying economy and to add the redundancies required to integrate intermittent sources of power across the province's large and diverse landscape. Commitments by BC Hydro to advance transmission and capacitor projects in the north and to continue considering options for expanded transmission to the north coast and Vancouver Island add needed focus to grid capacity in regions with strong wind energy potential. BC Hydro has also announced new investments in south coast transmission infrastructure to increase capacity in that region by 1,300 MW by 2040, in part through the addition of new substations, the expansion of regional transmission capacity, and the redevelopment of existing assets. C$21 billion out of the total C$36 billion in the Capital Plan will be dedicated to ensuring existing assets throughout the electricity system are able to accommodate increased demands on the system. As discussed in our last publication, political and economic momentum for Indigenous ownership of transmission assets in British Columbia continues to grow. This will have significant implications for the provincial grid, including for its governance, financing, and commercial operation, especially as large and capital intensive transmission projects such as the northwest transmission expansion continue to be advanced with strong Indigenous leadership. Government equity grant and loan guarantee programs for Indigenous infrastructure ownership (some of which are discussed in the Financing section of this chapter) are expected to form a key layer of the capital stack underpinning the current grid transformation.

Electricity Purchase Agreement Renewals

The EPA Renewal Program commenced on June 15, 2023 from the Signpost Update to the 2021 IRP with the BCUC. The Signpost Update and the Power Call were followed by an update to the 2021 IRP. The Signpost Update, among other matters, confirmed the need for new sources of power in the province sooner than had been anticipated in the 2021 IRP. One such source of power was through a program to renew electricity purchase agreements ("EPA Renewals"), and selecting 19 EPAs that were set to expire prior to April 1, 2026 to which BC Hydro offered standard EPA Renewal terms ("EPA Renewal Program").

On March 6, 2024, the BCUC approved the 2021 IRP, including a specific approval of the EPA Renewal Program ("2023 Approval"). Immediately upon the 2023 Approval as the first tranche of the EPA Renewal Program, the BCUC approved six EPA Renewals with IPPs pursuant to the process set out in section 71 of the Utilities Commission Act (British Columbia) and the BCUC Rules. We summarized the EPA Renewal Program and those six initial EPA Renewals in our publication last year.

Since our last publication, two more projects (being the Coats Hydroelectric Project and the Upper Mamquam Hydroelectric Project, discussed below) have been approved pursuant to the EPA Renewal Program. In addition to those two EPA Renewals, the BCUC also approved a third EPA Renewal – the Moresby Lake Hydroelectric Project – after BC Hydro came to terms with the relevant IPP through a bilateral negotiation process.

Approvals Subject to the EPA Renewal Program

As a result of the two additional EPA Renewals subsequent to the 2023 Approval, eight of the original 19 EPAs subject to the EPA Renewal Program have now been approved.

Coats Hydroelectric Project EPA Renewal

The Coats Hydroelectric Project EPA originally expired on December 31, 2023. The Coats Hydroelectric Project EPA Renewal was filed by BC Hydro to the BCUC on February 28, 2024, and approved by the BCUC on April 11, 2024. The Coats Hydroelectric Project EPA Renewal will last 20 years, from January 1, 2024, until January 1, 2044. The Coats Project operates on Gabriola Island, British Columbia and is operated by Crofter's Gleann Enterprises.

The Coats Hydroelectric Project is a 160 kW capacity small-storage hydro facility capable of generating 0.4 GWh of annual generation output, accounting for only 0.5% of the 900 GWh potentially available under the EPA Renewal Program as a whole. The Coats Hydroelectric Project is the smallest Project of the 19 associated with the EPA Renewal Program. The energy price for the outputs of the Coats Hydroelectric Project are C$58/MWh, increasing at 50% of the Consumer Price Index ("CPI") beginning January 1, 2024. The electricity that BC Hydro purchases from the Coats Hydroelectric Project will remain fixed at this inflation-adjusted rate for the Project's additional 20-year term.

Upper Mamquam Hydroelectric Project EPA Renewal

The Upper Mamquam Project EPA Renewal was filed by BC Hydro to the BCUC on September 12, 2024, and approved by the BCUC on October 10, 2024. The Upper Mamquam Hydroelectric Project EPA was set to expire on July 23, 2025. The current Upper Mamquam Hydroelectric Project EPA will continue on its terms until that date, after which the EPA Renewal will last for 20 years, from July 23, 2025, until July 23, 2045. The Upper Mamquam Project operates near Squamish, British Columbia and is owned by Canadian Hydro Developers, Inc.

The Upper Mamquam Hydroelectric Project is a 25-MW capacity run-of-river hydro facility capable of generating 108 GWh of annual generation output, accounting for 12% of the 900 GWh potentially available under the EPA Renewal Program as a whole. Like the Coats Hydroelectric Project and all other fixed-rate project approvals stemming from the EPA Renewal Program, the energy price for the outputs of the Upper Mamquam Hydroelectric Project are C$58/MWh, increasing at 50% of CPI beginning January 1, 2024. The electricity that BC Hydro purchases from the Upper Mamquam Hydroelectric Project will remain fixed at this inflation-adjusted rate for the Project's additional 20-year term.

The Moresby Lake Hydroelectric Project Negotiated EPA Renewal

The Moresby Lake Hydroelectric Project EPA Renewal is unique, as it was a bilaterally negotiated contract for an EPA Renewal between BC Hydro and the relevant IPP for an EPA that was never subject to the EPA Renewal Program. As a result, the terms of the Moresby Lake Hydroelectric Project differ from the EPA Renewals subject to the EPA Renewal Program.

From March 23, 1989 until August 31, 2022, the Moresby Lake Hydroelectric Project operated under its original EPA. The BCUC's Moresby Lake Hydroelectric Project EPA Renewal implements both: (i) an extension of the EPA from March 1, 2024 until March 14, 2024; and (ii) the EPA Renewal, which will apply from March 15, 2024 until March 15, 2034. The electricity purchase price of the Moresby Lake Hydroelectric Project EPA Renewal is not publicly available, but is less than C$350/MWh, according to BC Hydro's EPA Renewal Application for the Moresby Lake Hydroelectric Project.

The Moresby Lake Hydroelectric Project operates near Sandspit, British Columbia on Haida Gwaii. The Project is operated by Atlantic Power (Coastal Rivers) Corporation (Atlantic Power). The project's expected annual generation output of 21 GWh represents about 75% of the energy needs of Sandspit. The only other currently viable alternative to this project for electricity supply to Sandspit would be met by diesel generation, which would be significantly more costly, and would have increased environmental impacts as compared to the Moresby Lake Hydroelectric Project.

Due to the Moresby Lake Hydroelectric Project's location in Haida Nation territory on Haida Gwaii, BC Hydro was required to consult with the Council of the Haida Nation about the EPA Renewal. As a result of this consultation, Atlantic Power entered into a Memorandum of Understanding with Tll Yahda Energy (the clean energy Partnership of the Haida Nation) in relation to the EPA Renewal. The details of the Memorandum of Understanding are not public. Subsequent to signing the Memorandum of Understanding, the Council agreed to accept the EPA Renewal.

The Moresby Lake Hydroelectric Project EPA Renewal application was filed by BC Hydro to the BCUC on May 14, 2024, and approved by the BCUC on August 23, 2024.

Site C Update

Almost a decade after work began on BC Hydro's Site C Clean Energy Project ("Site C"), a hydroelectric dam and generating station on the Peace River in northeastern British Columbia, the project is at last nearing completion, expected to achieve its final unit in-service date in fall 2025.

Downstream of the existing W.A.C. Bennett and Peace Canyon dams, Site C is expected to generate about 35% of the energy produced at the W.A.C. Bennett Dam with only 5% of its reservoir area by utilizing the waters of the Williston Reservoir (the province's largest reservoir), which will collect water to be used again in a newly created 83-km-long reservoir for water storage. Site C is projected to provide 1,100 MW of capacity and generate 5,100 GWh of energy annually, which BC Hydro states is sufficient to power 450,000 homes or 1.7 million electric vehicles each year. Overall, Site C is expected to increase British Columbia's electricity supply by 8%.

The 11-week project to fill Site C's newly created reservoir in the Peace River Valley began in late summer of 2024 and was completed in early November 2024, with the first of six 183-MW generating units coming into operation in October. As of April 2025, four of six generating units are operational, some months ahead of schedule, with the fifth in the testing and commissioning stage, such that two thirds of Site C's generating capacity is now operational. The remaining units will be activated sequentially, with all six projected by BC Hydro to be operational by November 2025, realizing the full extent of Site C's energy generation capacity.

Although Site C has faced continual controversy and delays, BC Hydro's project reporting states that the overall project health is on target, with only moderate issues relating to safety and Indigenous relations. As of December 2024, costs were C$14.2 billion, with an estimated remaining expenditure of C$1.8 billion based on the forecasted total cost of C$16 billion – more than double the original estimated cost of C$6.6 billion. The project faced multiple legal challenges in the course of its planning and implementation, including from Treaty 8 First Nations whose traditional territories were impacted by the project and its reservoir. BC Hydro has a mandate from the Government to enter into Project or Impact Benefit Agreements with the 10 Indigenous groups most impacted by Site C, and it reports that it has executed and implemented Project or Impact Benefit Agreements with eight out of 10 Nations and continues to extend an offer to negotiate with the remaining two Nations.

While at times the need for the electricity generated by Site C was debated, as we have reported in previous years, the energy needs for British Columbia now projected by BC Hydro suggest demand that will quickly outstrip the supply from Site C, opening opportunities for independent power producers to supply the shortfall.

Clean Energy Initiatives in B.C.

British Columbia's Clean Energy Strategy

In June 2024, the Government released the province's new clean energy strategy, Powering Our Future: BC's Clean Energy Strategy ("Clean Energy Strategy"). The Clean Energy Strategy, which builds on other clean energy initiatives such as the BC Hydrogen Strategy and the Power Call, focuses on 10 areas including energy efficiency, increasing and diversifying clean energy sources, innovation and trading power with neighbouring jurisdictions. Actions under the Clean Energy Strategy include, among others: (i) investing C$700 million in BC Hydro energy-efficiency programs over the next three years; (ii) streamlining upgrades and new customer connections to BC Hydro's electricity grid to support the construction of new housing developments in growing communities; (iii) conducting regular, competitive calls for power every two years to meet growing demand; and (iv) increasing the target for renewable fuels produced in the province to 1.5 billion litres per year by 2030.

Update on CleanBC and the Roadmap to 2030

The CleanBC Roadmap to 2030 ("CleanBC") provides the framework to reduce the province's emissions by 40% by 2030 and includes initiatives aimed at reducing emissions from a range of industrial sectors. As part of efforts to achieve the 2030 target, the Government transitioned from carbon taxes to an output-based pricing system ("OBPS") for industry on April 1, 2024. The OBPS is an industrial carbon pricing system and is mandatory for operations that emit over 10,000 tonnes of carbon dioxide equivalent ("tCO₂e") per year and incentivizes industrial emitters to reduce their emissions by using a performance-based system. Industrial operations within a regulated sector that emit less than 10,000 tCO₂e per year may opt-in to the OBPS. Under the OBPS, operations are assessed on an annual basis. Compliance emissions for April 1, 2024 to December 31, 2024, will be based on the emissions intensity of their production for the 2024 calendar year. Operations that emit under their annual emissions limit will earn credits, while operations that emit over their emissions limit will have compliance obligations. Compliance options include applying earned credits, provincial offset units or direct payments. As the transition to the OBPS is completed, the CleanBC Industrial Incentive Program ("CIIP") will be phased out.

To support the province's 2030 emissions targets under CleanBC, a new industrial electrification program under the CleanBC Industry Fund was introduced in partnership with BC Hydro in 2024 to support industrial electrification projects. See the Financing section of the British Columbia Regional Overview for further discussion of this program.

Financing

In 2024, the rollout of funding programs offered by the Government and BC Hydro in support of the Province's clean energy objectives continued. Two key focuses of these programs, particularly in relation to the Power Call, are (i) industrial electrification and (ii) ensuring meaningful Indigenous equity ownership. Some of these programs are discussed in more detail below.

Industrial Electrification

In furtherance of the province's ambitious 2030 emissions targets under the CleanBC framework, a new industrial electrification program under the CleanBC Industry Fund ("CIF") was introduced in partnership with BC Hydro in 2024 to support industrial decarbonization and emissions reductions projects in the province. The program will facilitate large industrial low-carbon electrification projects, namely through interconnection of industrial facilities into the BC Hydro clean energy power grid. To be eligible, an industrial operator must be a "reporting operation" under the Greenhouse Gas Industrial Reporting and Control Act (British Columbia) and must be an existing BC Hydro customer (or become a BC Hydro customer upon completion of the project).

Under this program, successful applicants can receive up to (A) 75% of eligible costs for capital funding (consisting of (i) funding under the CIF of up to C$25 million and (ii) project funding from BC Hydro determined by the demonstrated financial need for funding and the levelized incentive on a $/tCO₂e basis for the project) and (B) 75% of eligible interconnection study costs under the CIF (up to a maximum of C$250,000 per project) for large-scale electrification projects. Funding awards for both categories of costs were determined on a project-by-project basis. BC Hydro has committed over C$5 billion over the next decade in their 2025-2034 Capital Plan (see above for more detail) to industrial and other electrification programs.

Indigenous Equity Ownership

A number of targeted funding programs to ensure meaningful Indigenous equity ownership in clean energy projects are being utilized in the province.

Since our last publication, a new funding stream under the BC Indigenous Clean Energy Initiative ("BCICEI") to support the development of small-scale First Nation-led clean energy projects has been advanced. As we discussed previously, the Government announced a C$140-million contribution to this new BCICEI funding stream to accompany the Power Call, which is expected to help advance Indigenous-led projects that may not otherwise be competitive due to their smaller size. To be eligible for funding under the BCICEI funding stream, the following criteria must be satisfied:

1. applicants must be British Columbia First Nations, Tribal Councils or legal entities majority-owned and controlled by First Nations communities;
2. the projects being funded must also be majority-owned by First Nations;
3. the projects being funded must generate electricity from clean or renewable resources (as defined under the CEA); and
4. the projects being funded must be capable of connecting to BC Hydro's integrated power grid (which must also be able to accommodate the additional proposed electricity).

Preference will be given to projects that are wholly owned by First Nations, have previously received BCICEI funding under other streams, and are greater than BC Hydro's net metering program threshold and less than 15 MW in nameplate capacity.

Further supporting Indigenous equity ownership in clean energy projects, in theirBudget and Fiscal Plan 2024/25-2026/27 (Budget 2024), the Government announced a new First Nations Equity Financing Framework ("Framework") to support equity loan guarantees and other potential forms of assistance to facilitate Indigenous participation in projects. Amendments to the Special Accounts Appropriation and Control Act (British Columbia) passed in conjunction with Budget 2024 established a First Nations Equity Financing special account ("FNEF Account") on the Government's balance sheet with an initial balance of C$10 million to provide immediate capacity funding to Indigenous groups considering equity participation in projects. Under the Special Accounts Appropriation and Control Act (British Columbia), the provincial Treasury Board is authorized to fund the FNEF Account with government revenue and the Minister of Finance may provide capacity grants and loan guarantees to support Indigenous equity participation in projects up to an aggregate loan guarantee limit of C$1 billion. Although this loan guarantee program will not be rolled out in time for use in the current Power Call, it is expected to be deployed for use at scale in subsequent BC Hydro calls for power.

In further support of the First Nation ownership requirements under the current and future BC Hydro calls for power, Canada Infrastructure Bank ("CIB") announced two new financing products for call participants. These are an Indigenous equity loan program to help First Nation project participants finance up to 90% of their equity holding in a project that receives an electricity purchase agreement and a CIB program to extend investment tax credit bridge financing for up to 30% of project costs (see Tax Incentives for Clean Energy chapter of this publication for further details). These two CIB products must be used together for a given project, and cannot be used independently. Documents related to this financing program are being sent directly to call participants by CIB.

These funding and loan guarantee programs dovetail with the First Nations ownership requirements under the Power Call, which are expected to be carried forward into future BC Hydro calls for power.

FortisBC

FortisBC, both the largest gas utility and the largest private electrical utility in the province, has been engaging in its own clean energy development and procurement initiatives to reduce its greenhouse gas emissions while expanding its service offerings to meet growing demand. For gas, a major focus of FortisBC has been decarbonizing its natural gas operations while meeting delivery requirements under its regulated rate framework. On the electricity side, FortisBC has launched a Request for Expressions of Interest for New Power ("RFEOI") to evaluate options for procuring clean electricity to supply future demand. Both are discussed in further detail below.

Decarbonization

FortisBC has invested almost C$5 million annually between 2020 and 2024 towards clean energy innovation projects in the province through their Clean Growth Innovation Fund. These investments have supported the research and development of hydrogen and renewable natural gas fuel technologies, as well as carbon capture utilization and storage and energy efficiency programs. On April 8, 2024, FortisBC sought approval from the BCUC to continue the fund beyond 2024 as part of its Application for Approval of a Rate Setting Framework for 2025 through 2027. The decarbonization of natural gas through blending with lower carbon fuels, carbon capture and reduction of leakage are expected to play a significant role in reducing emissions while leveraging existing utility infrastructure to save on capital costs in light of the large expenditures required for the energy transition.

Procurement of New Clean Electricity

To serve growing electricity demand in its service area, FortisBC expects to require up to an additional 100 MW of additional electricity by 2030 and up to 340 MW in additional capacity by 2040 (requiring as much as 1,100 GWh of annual energy by 2030 and up to 2,300 GWh of annual energy by 2040). To plan for this growth, in September 2024 FortisBC launched its RFEOI to survey the market for clean power sources and consider its supply options. The stated purpose of the RFEOI, which is a solicitation of interest and not a procurement process, is to "identify and gather information on potentially feasible generation projects in British Columbia and inform next steps." FortisBC will be exploring projects which utilize wind, solar, hydroelectricity, or other clean or renewable resources (as defined under the CEA), among other technologies. Projects of greatest interest will be those which have a nameplate capacity of 5 MW of more, are in the province (but not necessarily in FortisBC's service area), are Indigenous-led or have significant Indigenous ownership and are innovative and capable of adding value beyond the power they will supply. A range of supply capabilities, including firm and non-firm energy sources, will be accepted for consideration. The initial procurement process related to the RFEOI is expected to launch in Q2 of 2025. The procurement process that is launched from the RFEOI may be attractive to project proponents who are unsuccessful in the Power Call or who desire greater commercial flexibility to negotiate bespoke provisions in supply agreements tailored to their unique projects.

Liquid Natural Gas ("LNG") Update

In the past year, several LNG projects in British Columbia have achieved significant regulatory, construction and financial milestones.

Currently, there are seven Canadian LNG export projects at various stages of development – all of which are located in the province. In May 2024, the federal government reported that these projects could represent capital investments of around C$109 billion. As of November 2024, the federal government has granted five LNG export licenses, ranging from 25 to 40 years, thus setting the stage for LNG exports to start as early as 2025.

Recent geopolitical tensions with the United States have led to a renewed political appetite for LNG projects as means to diversify Canadian energy exports. The Government has expressed, albeit qualified, support for LNG projects in the province. In 2023, they introduced an energy action framework, which proposed new requirements for future LNG facilities and the province's oil and gas industry participants to align with the province's emissions-reduction goals. Shortly thereafter, the Government issued its Oil and Gas Emissions Cap Policy Paper. The paper sets out examples of how LNG may meet zero emissions by 2030, such as adopting best-in-class technology and offsetting emissions through verified carbon-offset projects. Similarly, the federal government continues to support and fund LNG projects in British Columbia, including a C$200-million contribution to Cedar LNG in March 2025.

LNG Canada

In September 2024, LNG Canada – a joint venture between Shell, Petronas, PetroChina, Mitsubishi Corporation and Korea Gas Corporation – reported its Phase 1 construction was 95% complete with natural gas introduced to the facility for the first time.

LNG Canada's Phase 1 is scheduled to begin shipments to Asia in 2025, with the goal of exporting 14 million tonnes of LNG per year. This C$40-billion project is located in Kitimat, British Columbia, and was the first large-scale LNG export facility to announce a final investment decision in the province. The terminal is being built on the head of the Douglas Channel, on the traditional territory of the Haisla Nation.

A final investment decision has not yet been made for Phase 2 of LNG Canada, which would double the exporting capacity of the facility from 14 million to 28 million tonnes per year. LNG Canada and BC Hydro are reported to be making progress in their discussions about the prospect of increasing the hydroelectricity capacity that would be required if Phase 2 switches to electric motors to power its liquefaction compressors. However, we are not aware of final plans having been made to build the required infrastructure in time to make the Phase 2 build-out electric.

Cedar LNG

Cedar LNG is the largest Indigenous majority-owned infrastructure project in Canada. Cedar LNG is a Haisla Nation majority-owned partnership with Pembina Pipeline Corporation. This US$4-billion project is also proposed to be located in Kitimat, British Columbia, on Haisla Nation-owned land, and would be supplied with natural gas from the now-complete Coastal GasLink pipeline. When built, Cedar LNG would produce approximately three million tonnes of LNG per year.

Notably, British Columbia's energy action framework was announced after the approval of the Cedar LNG project in 2023, such that it will not be subject to the more onerous emissions and net-zero requirements that will apply to those LNG facilities that are currently in, or will undergo, the environmental assessment process. The Cedar LNG project will still be subject to certain ongoing terms, conditions and requirements set out in its environmental assessment certificate and the impact assessment decision.

Another significant milestones for the Cedar LNG project include the signing of a heads of agreement in November 2023 with Samsung Heavy Industries ("SHI") and Black & Veatch ("B&V") to reserve shipyard capacity for LNG modules construction. In January 2024, Cedar LNG selected SHI and B&V to provide engineering, procurement and construction services for the design, fabrication and delivery of the project's floating LNG production unit subject to a final investment decision ("FID"). Cedar LNG announced a FID in June 2024.

Woodfibre

The Woodfibre LNG project located near Squamish, British Columbia, is currently under construction with work foundations for the LNG processing equipment and modules expected to arrive in 2025. Woodfibre LNG is co-owned by Pacific Energy Corp. (70%) and Enbridge (30%) and is expected to export 2.1 million tonnes per year of LNG. The project, including its compressors, will be powered by renewable hydroelectricity and is stated to be the cleanest LNG facility in the world. The project is set to begin operations in 2027 in Howe Sound and plans to meet net-zero emissions by the time operations commence. To accelerate construction, Woodfibre LNG applied for a second floatel in May 2025 to house an additional 900 skilled workers to build the project.

FortisBC commenced construction in August 2023 of the Eagle Mountain pipeline, a 38-km-long, 24-in-diameter pipe to supply gas to the Woodfibre LNG project.

Ksi Lisims

In 2024, Ksi Lisims LNG, a Nisga'a Nation-led C$10-billion project which also includes Western LNG and Rockies LNG, achieved two major milestones. First in January 2024, Ksi Lisims LNG finalized a 20-year LNG purchase and sale agreement with Shell Eastern Trading Pte Ltd. This agreement comes less than a year after the Ksi Lisims LNG project received the go-ahead to enter the province's environmental review process. Second, on June 21, 2024, the Nisga'a Nation and Western LNG purchased the Prince Rupert Gas Transmission project ("PRGT") with plans to re-route the pipeline and connect it to Ksi Lisims LNG. The Ksi Lisims LNG project aims to export 12 million tonnes of LNG per year, making it Canada's second-largest LNG export facility.

The Ksi Lisims LNG project and PRGT are both under review by the Environmental Assessment Office (the "EAO"). The EAO has requested that Ksi Lisims LNG provide "credible plans" to attain net-zero emissions by 2030 to comply with the energy action framework and obtain an environmental certificate. Accordingly, Ksi Lisims plans on using floating facilities, with hydroelectricity powering motors for compressors in the liquefaction process. In contrast, PRGT has an environmental certificate that was supposed to expire on November 25, 2024 and the EAO is reviewing a request by PRGT to make the certificate permanent.

Tilbury

Tilbury LNG is a proposed two-phased expansion of an existing FortisBC facility, located on Tilbury Island in Delta, British Columbia. FortisBC is in the early planning stages to complete Phase 1 of the expansion to its liquefaction capacity, which could complete construction as early as 2028.

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