On February 27, 2018, Finance Minister Bill Morneau tabled in the House of Commons the Liberal Government’s third budget, Equality + Growth = A Strong Middle Class (“Budget 2018”). Budget 2018 proposes to extend eligibility for accelerated capital allowance in Class 43.2 by five years so that it would be available for property acquired before 2025. Generally, investments in specified clean energy generation and conservation equipment may qualify for accelerated capital cost allowance rates by being included in either Class 43.1 (30% on a declining balance basis) or Class 43.2 (50% on a declining balance basis). The eligibility criteria for these two capital cost allowance classes are generally the same, except that Class 43.2 has a higher efficiency standard for cogeneration systems that use fossil fuels than Class 43.1. Providing accelerated capital cost allowance is intended to encourage investment in specified clean energy generation and energy efficiency equipment that will contribute to a reduction in emissions of greenhouse gases and air pollutants. For a discussion of these tax measures as well as others in Budget 2018, please see McCarthy Tétrault’s Budget 2018 Commentary
In January, the provincial government of Nova Scotia announced in a news release that it will finally go forward with its tidal energy project, first announced in 2015, in the Bras d’or Lakes and the Bay of Fundy. Businesses or research firms wishing to obtain tidal energy demonstration permits are therefore encouraged to submit their application to the Department of Energy’s offices.
In launching this project, the Province hopes to encourage innovation and to support sustainable growth in the tidal energy industry. The project is also consistent with the Province’s long-term goal of maintaining its standing as a world leader in renewable energy, particularly in the nascent field of tidal energy. The unique geography of Nova Scotia provides the Province with enormous potential in this respect. Continue Reading
On February 14, 2018, the Government of Québec published for consultation purposes 24 draft regulations aimed at implementing significant amendments made to the Québec Environment Quality Act.
We invite you to read this article posted on our Canadian ERA Perspectives blog.
We invite our readers to read an interesting article posted by our colleagues on our Canadian ERA Perspectives blog regarding the introduction by the federal government of the new Impact Assessment Act. It can be accessed here.
On February 8, 2018, the Federal Government announced the first reading of Bill C-69: An Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts (Bill C-69).
While Bill C-69 proposes to amend a multitude of Federal legislation, this article focuses on its impact on the National Energy Board (NEB). For a discussion of the other changes introduced through Bill C-69, please refer to McCarthy Tétrault’s other blog posts on this topic which can be found here.
What does Bill C-69 mean for the NEB?
Upon Bill C-69 coming into force, the National Energy Board Act (NEB Act) will be repealed and replaced by the Canadian Energy Regulator Act (CER Act). Bill C-69 will also reincarnate the NEB as the Canadian Energy Regulator (CER), which will continue to be based in Calgary. Continue Reading
Building from the momentum of Round 1 of the Alberta Electric System Operator’s (AESO) Renewable Electricity Program (REP), the Government of Alberta directed the AESO to develop Round 2 (REP 2) and Round 3 (REP 3). The AESO will open REP 2 and REP 3 in early 2018 and will run the two competitions in parallel. It is anticipated that the successful bidders will be announced by the end of 2018.
REP Round 2:
REP 2 will have a procurement target of 300 MW and will include an Indigenous equity ownership requirement. Each bid within REP 2 will have a minimum Indigenous equity component, which can include an ownership stake in the project or land use agreement between the company and the community. The Indigenous community must be located in Alberta.
For the purposes of REP 2, the Government of Alberta has defined Indigenous as one of the following:
- First Nation communities, Métis Settlements, Métis Nation of Alberta, and the Aseniwuche Winewak Nation; or
- Indigenous-community owned organization and/or business.
George Vegh, the head of McCarthy Tétrault’s Toronto energy regulatory practice, recently sat down for an interview on the topic of energy governance with University of Toronto radio as part of their Beyond the Headlines Insight Series.
A full version of the episode can be found here. George Vegh’s interview starts at 37.13.
On January 18, 2018, the Alberta Electric System Operator (AESO) launched a public assessment of dispatchable renewables and storage. According to the direction letter, the Government of Alberta (Province) seeks to understand the role dispatchable renewable development can play in achieving Alberta’s legislated 30 by 30 target of 30 percent renewable generation by 2030 (30 by 30 Target). This announcement comes in the wake of the announcement of the Round 1 REP results, a summary of which can be found in a previous post.
On-demand or dispatchable renewable can provide a valuable service to Alberta’s interconnected electricity system (AIES) and its reliability. Such value is increasingly important given the significant intermittent generation being brought onto the AIES through initiatives such as the AESO’s Renewable Electricity Program (REP).
What’s being done?
The Province directed the AESO to undertake additional analysis and stakeholder engagement (including engaging technical advisors) to review the electricity system requirements and to determine:
- the need for on-demand renewables; and
- the best means to secure these system benefits through a competitive process.
This analysis and assessment will be coordinated with the AESO’s ongoing capacity market design work and any future REP competitions.
McCarthy Tétrault’s Power Group has launched its third annual year-end power industry publication: ‘Canadian Power – Key Developments in 2017, Trends to Watch for in 2018’. The publication provides a detailed overview of significant developments in the Canadian power sector over the past year, as well as emerging trends that will be relevant in the year ahead. Information includes a review of the British Columbia, Alberta, Ontario and Québec power industries in 2017, and topics discussing recent M&A transactions and Aboriginal and environmental law developments.
An area of focus for 2018 will be regulatory reform at the Ontario Energy Board (“OEB”), particularly in the area of technological innovation and empowering customers. Both the Minister of Energy and the OEB have launched initiatives to address, among other things, how the OEB can facilitate the use of innovative technologies, such as smart grid and storage through changes to OEB processes and rate design. One of the major areas of review will likely be with respect to the ability of local distribution companies to invest in “non-wires” solutions and recover the costs of these investments by rate payers. The OEB and the Minister may have different perspectives on this issue and it will be interesting to see how these dual, and perhaps competing initiatives will play out in 2018.
Links to both announcements are included below:
In November 2016, the federal government announced that it would commence development of a performance-based clean fuel standard (CFS) that would incent the use of a broad range of low carbon fuels, energy sources and technologies. The objective of the CFS is to achieve 30 megatonnes (Mt) of annual reductions in greenhouse gas (GHG) emissions by 2030, as part of efforts to achieve Canada’s overall GHG emissions reduction target of 30% below 2005 levels by 2030. As announced earlier by the federal government, the proposed CFS would establish lifecycle carbon intensity requirements separately for liquid, gaseous and solid fuels, and would go beyond transportation fuels to include those used in industry and buildings. The approach would not differentiate between crude oil types that are produced in Canada or imported.
Stakeholder consultations on the proposed CFS were held throughout 2017; in November 2017, Environment and Climate Change Canada (ECCC) released a report prepared by the International Institute on Sustainable Development, which summarizes stakeholder comments received in response to the federal government’s discussion paper on the CFS that was released in February 2017. On December 13, 2017, ECCC published a regulatory framework on the clean fuel standard. The framework outlines the key design elements for the CFS regulation, including its scope, regulated parties, carbon intensity approach, timing, and potential compliance options such as credit trading.
As noted above, the CFS will use a lifecycle approach to set carbon intensity values and requirements, accounting for the amount of GHG emitted to produce a unit of energy. The proposed lifecycle approach will assess GHG emissions from all stages in a product’s life, from cradle to grave (i.e. from raw material extraction through materials processing, manufacture, distribution, use, repair and maintenance, and disposal or recycling where applicable). ECCC expects that the CFS may lead to changes in crop demand and land management practices that impact GHG emissions, which will be included. However, indirect GHG emissions that may result from the clean fuel standard will not be considered in the design, at least initially.
The proposed CFS regulatory framework covers the following elements:
- Partitioning: In order to achieve reductions from each of the transportation, building and industry sectors, the CFS will set separate carbon intensity requirements for sub-sets of fuels, as well as rules for credit trading. In particular, the CFS will set separate carbon intensity requirements for liquid, gaseous and solid fuel streams. For gaseous fuels, consideration will be given to setting volumetric requirements for renewable content or a hybrid approach, such as volumetric requirements with GHG performance standards. Approximately 80% of liquid fuels are used for transportation. Setting a separate carbon intensity target for liquid fuels will ensure GHG reductions are achieved from transportation fuels. Consideration may be given to further groupings of fuel types within fuel streams (e.g. grouping transportation fuels together in the liquid fuel stream), along with some trading of credits between the fuel streams.
- Scope of CFS Regulations: The CFS will apply to liquid, gaseous and solid fuels combusted for the purpose of creating energy including “self-produced and used” fuels, that is, those fuels that are used by producers or importers. The CFS will not apply to fuels when they are primarily used as feedstocks in industrial processes or when used for non-combustion purposes (for example, solvents). Certain fuels will be excluded from application of the carbon intensity requirements of the clean fuel standard, including fuels that are exported from Canada, fuels that are in transit through Canada, and coal combusted at facilities that are covered by coal-fired electricity GHG regulations. Other exclusions may be considered.
- Regulated Parties: Fuel producers and importers, or in some cases distributors, will be subject to the clean fuel standard and will need to meet specific requirements for the fuels that they produce, import or distribute.
- In the case of liquid fuels:
- the producers or importers of the liquid fuel (for example, gasoline, diesel, and heavy fuel oil) will be the regulated parties.
- In the case of gaseous fuels:
- for pipeline-quality natural gas delivered via gas distribution pipeline systems, the distributors of the natural gas will be the regulated parties;
- for other gaseous fuels supplied to end-users other than through a gas distribution pipeline system (for example, biogas, natural gas from producers),the regulated parties remain to be determined.
- In the case of solid fuels:
- the producers or importers of the fuel (for example, coal and petroleum coke) will be the regulated parties.
- In the case of liquid fuels:
- Approach to setting requirements: Carbon intensity values will be expressed in grams of carbon dioxide equivalents (g CO2e) per unit of energy in megajoules, and will account for GHG emissions over the lifecycle of a fuel. Carbon intensity values will not include an estimate of the impact of indirect land use change on GHG emissions. Baseline carbon intensity values and carbon intensity requirements will be set for either each fuel in a stream (liquid, gaseous, solid) or for groupings that include some or all fuels in a stream. The CFS regulations will set carbon intensity requirements expressed either as absolute values or as percent reductions from the relevant baselines. The carbon intensity requirements will become more stringent over time, with the goal of achieving at least 30 Mt CO2e of emission reductions annually commencing in 2030.
- Calculation of Lifecycle Carbon Intensity of Fuels: For renewable fuels, other low carbon fuels and energy sources and technologies, carbon intensity will be differentiated by type and origin of the fuel to reflect the GHG emissions associated with different feedstocks and technologies. In the case of crude oil-based fuels, the regulation will not differentiate among crude oil types, or on whether the crude oil is produced in or imported into Canada. A Canadian-average default carbon-intensity for crude oil produced and imported and consumed in Canada will be used. For other fossil fuels, consideration is being given to whether or not the same approach as for crude oil-based fuels should be applied.
- Renewable Fuel Content: The federal Renewable Fuels Regulations currently require 5% renewable content in gasoline and 2% renewable content in diesel fuel and heating distillate oil. In the short-term, these volumetric requirements will be maintained. In the longer-term, the CFS will replace the Renewable Fuels Regulations. With respect to natural gas, setting carbon intensity requirements is the intended approach, but further consideration will be given to setting volumetric requirements for renewable content or a hybrid approach, such as volumetric requirements with GHG performance standards.
- Compliance Pathways: The CFS will provide a range of pathways for compliance other than reducing the carbon intensity of the fuel produced or imported for use in Canada. A key pathway for fossil fuel suppliers will be to include renewable fuel content in their product. Under the proposed CFS regulations, it will be possible to generate compliance credits for actions that improve carbon intensity throughout the lifecycle of the fuel. One issue to be determined is whether to specify a minimum threshold for process improvements that qualify for credit creation. It will also be possible to generate credits through fuel switching and the deployment of energy sources and technologies that displace fossil fuels, such as electric vehicles. Credits will be tradeable among regulated parties within each stream of fuels (liquid, gaseous and solid). There will also be limited banking of credits. Consideration is being given to allowing some use of credits across streams of fuels.
- Timing of Requirements: ECCC plans to publish draft regulations in Canada Gazette, Part I in 2018 and final regulations in Canada Gazette, Part II in mid-2019. Carbon intensity requirements for liquid, gaseous and solid fuel streams will come into force at the same time; however, the coming into force date is still to be determined.
Given the multiple layers of regulations that are already in place at the federal and provincial levels, careful consideration will need to be given to how the implementation of the CFS will impact provincial initiatives. For an overview of the current federal and provincial regulatory framework for renewable fuels, please refer to our earlier blog. Written comments on the CFS regulatory framework are being accepted by ECCC until January 19, 2018. Comments received in writing and as part of the upcoming engagement on technical details will inform the design of draft regulations to be published in late 2018.
On December 13, 2017, the Government of Alberta announced the results of Round 1 of the Renewable Energy Program (REP). The successful bids set a record for the lowest renewable electricity pricing in Canada, ranging from $30.90 to $43.30 per MWh with a weighted average price for the successful bids of $37 per MWh or 3.7 cents per kWh.
Summary of Results
REP Round 1 delivered more than the anticipated 400 MW with almost 600 MW of wind generation from the following four projects:
- EDP Renewables Canada Ltd. – Sharp Hills Wind Farm (248.4 MW) in Oyen, Alberta
- Enel Green Power Canada, Inc. – Phase 2 (30.6 MW) of Castle Rock Ridge Wind Power Plant in Pincher Creek, Alberta
- Enel Green Power Canada, Inc. – Riverview Wind Farm (115 MW) in Pincher Creek, Alberta
- Capital Power Corporation – Whitla Wind (201.6 MW) in Medicine Hat, Alberta
While the Alberta Electric System Operator (AESO) has not yet released the final form of the Renewable Electricity Support Agreement (RESA), it did release the Fairness Advisor’s Report for REP Round 1, a copy of which can be found here.
Twelve proponents submitted bid prices for 26 projects in the RFP stage of REP Round 1. The proponent names are listed alphabetically below:
- BHEC – RES Alberta L.P.
- BowArk Energy Ltd.
- C&B Alberta Solar Development ULC
- Capital Power Corporation
- EDF EN Canada Inc.
- EDP Renewables Canada Ltd.
- Enel Green Power Canada Inc.
- Invenergy Wind Global LLC
- NaturEner Energy Canada Inc.
- NextEra Canada Development LP
- Potentia Renewables Inc.
- TransAlta Corporation
REP Round 2?
To date, no concrete plans regarding the timing of REP Round 2 have been announced. More details are expected in early 2018. With stunningly low prices, we anticipate that the Government of Alberta may seek to launch Round 2 as soon as possible to continue progressing toward meeting its target of 30% renewable electricity by 2030 (30 by 30 target). Whether such low prices can be sustained or replicated in future rounds will depend upon the evaluation factors and project criteria (e.g. geographic, Indigenous participation or municipal involvement) identified in each round by the Government of Alberta. Each of the REP Round 1 projects can be connected to the existing transmission system with no new transmission costs or upgrade requirements; however, Alberta’s 30 by 30 target cannot be achieved solely through such selection criteria. As a result, Albertans would be prudent not to treat these very low prices as the market benchmark.
On December 11, 2017, the B.C. government announced its decision to complete construction of BC Hydro’s 1,100-megawatt Site C Clean Energy Project (Site C), concluding that cancelling the project mid-construction would have imposed a $4 billion burden on provincial taxpayers, comprising $2.1 billion already spent and an estimated $1.8 billion in termination and site remediation costs. The B.C. government also confirmed that the capital cost estimate for Site C has been updated to $10.7 billion from BC Hydro’s original estimate of $7.9 billion.
A copy of the B.C. government’s press release, which includes links to relevant background materials, is available here.
In moving forward with the project, the B.C. government also announced a Site C “turnaround plan” to contain project costs and secure additional project-related benefits, including:
- a new “Project Assurance Board” to provide oversight over future contract procurement and management, project deliverables, environmental matters and quality assurance;
- a new community benefits program to ensure project benefits to local communities and to increase the number of apprentices and First Nations workers working on the project; and
- a new B.C. Food Security Fund to be funded by Site C revenues and dedicated to supporting farming and agricultural innovation and productivity in the province.
In addition, the B.C. government and BC Hydro will consider the development of a new procurement stream for smaller-scale renewable electricity projects where First Nations are proponents or partners, expanding or complementing BC Hydro’s existing Standing Offer Program.
Construction of Site C, which received provincial and federal environmental approvals in October 2014, began in summer 2015. Both prior to and since the start of construction, the project has faced significant opposition from various stakeholders, including landowners and First Nations in the Peace Region, several of whom launched court challenges against Site C. The Peace Valley Landowner Association’s proceedings against the government concluded in September 2016 when the B.C. Court of Appeal affirmed the lower court’s ruling that the decision by the Minister of the Environment was reasonable. In early 2017, the federal and BC appellate courts dismissed challenges of Site C’s federal and provincial environmental assessment approvals, which had been brought by the West Moberly and Prophet River First Nations.
In August 2017, the newly-elected N.D.P. government led by Premier John Horgan requested that the British Columbia Utilities Commission (BCUC) review the impact on BC Hydro ratepayers associated with continuing, suspending or terminating the Site C project.
Reporting in November 2017, the BCUC’s key findings included that:
- the Site C project is unlikely to be completed on time or on budget, and the BC Hydro load forecast underlying the project’s construction is excessively optimistic;
- suspending and restarting the Site C project in 2024 is by far the least attractive option, adding an estimated $3.6 billion to final costs and creating significant risk due to the expiration of applicable approvals and permits;
- project termination and remediation costs would be approximately $1.8 billion, in addition to the costs of finding alternative energy sources to meet demand; and
- increasingly viable alternative energy sources such as wind, geothermal and industrial curtailment could provide similar benefits to ratepayers as the Site C project, with an equal or lower unit energy cost.
Certain of the BCUC’s findings were subsequently challenged by the B.C. government, BC Hydro and others, but the regulator did not change its main conclusions. Following the publication of the BCUC report, the B.C. government consulted with a number of additional industry participants before coming to its decision to proceed with the completion of the project.
Site C will be the third dam and hydroelectric generating station on the Peace River in northeast B.C., and following its expected in-service date of 2024 will produce about 5,100 gigawatt hours of electricity each year – enough to power the equivalent of about 450,000 homes per year. In accordance with the province’s Clean Energy Act, Site C would be the last major hydroelectric project to be undertaken by BC Hydro.
On December 6, 2017, the Alberta Energy Regulator (AER) issued Bulletin 2017-21, announcing the release of a new edition of Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals (Directive 067).
Directive 067 was updated to increase the scrutiny applied by the AER in granting licences, and to licence holders generally. The AER stated that this increased scrutiny is aimed at ensuring the privilege of holding licences is “only granted to, and retained by, responsible parties”. The changes to Directive 067 appear to be another attempt by the AER to address issues stemming from the ongoing litigation pertaining to the Redwater case, which allowed a trustee to disclaim certain uneconomic assets under the provisions of the federal Bankruptcy and Insolvency Act. Commentary on the Redwater decisions can be found here and here.
McCarthy Tétrault LLP is pleased to announce that our partner Cameron Hughes has had his article titled “Earth, Wind, and Fire: Power Infrastructure in Alberta’s New Age” published in the Alberta Law Review.
A full copy of the article can be found here.
On December 6, 2017, the Alberta Energy Regulator (AER) issued Bulletin 2017-21, announcing the release of a new edition of Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals (Directive 067).
Directive 067 was updated to increase the scrutiny applied by the AER in granting licences, and to licence holders generally. The AER stated that this increased scrutiny is aimed at ensuring the privilege of holding licences is “only granted to, and retained by, responsible parties”. The changes to Directive 067 appear to be another attempt by the AER to address issues stemming from the ongoing litigation pertaining to the Redwater case, which allowed a trustee to disclaim certain uneconomic licenced assets under the provisions of the federal Bankruptcy and Insolvency Act. Commentary on the Redwater decisions can be found here and here.
Directive 067 was updated as follows: Continue Reading
On November 17, 2017, the Ontario Energy Association and the Association of Power Producers of Ontario released a report titled “Report on Energy Governance in Ontario” which was drafted by George Vegh, the head of McCarthy Tétrault’s Toronto energy regulatory practice. The report addresses how energy decisions are governed in Ontario and proposes solutions to improve it. The report concludes that energy agencies have not provided the check and balance function that regulators typically perform in other jurisdictions and finds that agencies are often the partner and implementer of political decision making rather than operating as providing a fact-based constraint on political decision making. The report recommends that energy governance should be improved to better reflect the principles of transparency, accountability and integration.
A full copy of the report can be found here.
During BC’s provincial election campaign in May 2017, the NDP promised to send the Site C project for review by the BC Utilities Commission (BCUC) if it was elected. Site C, a multi-billion dollar project to construct a third dam and generating station on the Peace River in northeast BC, had received approval from the previous BC Liberal government to begin construction in December 2014. After taking the reins of provincial government in July 2018, newly sworn in Premier John Horgan made good on his party’s promise and the government issued an Order in Council (OIC) requesting that BCUC undertake an inquiry into certain aspects of Site C. On November 1, 2017, BCUC’s four-member review panel (the Panel) delivered its final Site C Inquiry Report (the Final Report) to the government.
Scope of Review
As an exempt project under the BC Clean Energy Act, BCUC has no jurisdiction over the project. However, the inquiry was carried out under section 5 of the BC Utilities Commission Act, which enables the Lieutenant Governor in Council to set terms of reference and direct BCUC to inquire into any matter. Pursuant to the OIC, BCUC was asked to advise on the implications of:
- completing Site C by 2024, as currently planned;
- suspending Site C, while maintaining the option to resume construction until 2024; and
- terminating construction and remediating the site.
The government also requested that BCUC address a number of more specific issues such as what, if any, commercially feasible generating projects and demand-side management initiatives (e.g. energy efficiency programs) could provide similar benefits to ratepayers with an equal or lower per-unit energy cost as Site C could provide.
The Site C inquiry process was carried out in two phases. The first phase took place between early August and mid-September 2017, and involved fact gathering from BC Hydro, Deloitte LLP (which produced independent reports on many of the questions set out in the OIC), and members of the public. This data informed a preliminary report issued by BCUC on September 20, 2017. Following the issuance of the preliminary report, BCUC initiated the second phase of the process, which included further information gathering from BC Hydro and a series of community input sessions around the province, including meetings with First Nations. In total, BCUC received 620 written submissions and heard from 304 speakers during 11 community input sessions, with three additional First Nations input sessions and two technical presentation sessions. This information-gathering and consultation process was followed by a review period, which culminated in the publication of the Final Report.
Panel’s Key Findings
The Panel’s nearly 300-page report set out the following key findings:
- Completion Scenario: The Panel was not persuaded that Site C would remain on schedule for a November 2024 in-service date. Further, the Panel estimated that completion costs may exceed $10 billion and, in the worst case scenario, could exceed the proposed budget of $8.335 billion by 20 to 50%. The Panel also observed that completion could result in other negative consequences, such as potential infringement of First Nation treaty and Aboriginal rights.
- Suspension Scenario: The Panel found the suspension and potential restart scenario to be the least attractive of the three alternatives posed in the OIC. The Panel concluded that this alternative would be both the most expensive, adding at least an estimated $3.6 billion to final costs, and the most risky because, for example, existing environmental permits would expire and new approvals would be required, introducing uncertainty. The Panel further observed that contracts would have to be retendered and First Nations’ benefit agreements potentially renegotiated. In any event, the Panel added, there would be no guarantee that the project budget would be sufficient to complete the project following remobilization.
- Termination Scenario: The Panel estimated that termination and remediation costs of the project would reach approximately $1.8 billion, with additional costs of finding alternative energy sources to meet demand.
- Overly Optimistic Load Forecasts: The Panel found BC Hydro’s load forecasts (i.e., demand projections) to be overly optimistic. The Panel declined to adopt BC Hydro’s mid load forecast, instead adopting the low load forecast in performing its analyses. The Panel added that there remained a risk that demand would not even reach the low load forecast.
- Disruptive Factors: The Panel noted a number of disruptive factors that, in addition to construction and operating risk, would pose risks during the economic life of Site C and potentially reduce the anticipated benefits of the project. The Panel cited future technological advances in renewable energy and energy storage capacity through utility-scale battery storage, as well as other factors subject to considerable uncertainty such as the effects of climate change.
- Viable Alternatives: The Panel expressed its view that alternative energy sources such as wind, geothermal, and industrial curtailment could provide similar benefits to ratepayers as Site C, with an equal or lower per-unit energy cost.
The Panel acknowledged that neither completing Site C nor implementing a portfolio of alternative energy sources is without risks, which are explored further in the Final Report.
Fate of Site C is Now in BC Government’s Hands
So what does all of this mean for the future of Site C? It is first important to understand what the Final Report is not: it is not a recommendation as to which of the three alternatives referred to in the OIC should be pursued, nor is it a “decision” on the future of Site C or a “reconsideration” of decisions made in the environmental assessment process or by statutory decision makers or the courts. The Panel’s mandate was more modest, i.e. to provide information requested in the OIC. As clarified in the Final Report, the Panel took no position on which scenario should be pursued. Nonetheless, given the Panel’s concerns expressed in the Final Report, the BC government will need to carefully weigh the options in making a decision on whether to let Site C proceed, or whether to pull the plug on the project.
While the Final Report does not make any particular recommendation on Site C, the BC government has indicated that the future of the project remains uncertain. In a press release issued shortly after the issuance of the Final Report, Minister of Energy, Mines and Petroleum Resources Michelle Mungall outlined the next steps in the Site C saga: “Now it is our turn, as government, to determine whether Site C is in the best interests of British Columbians, after considering the BCUC’s findings and other issues outside the scope of this review.” As Minister Mungall noted, the government is faced with an “extremely difficult decision” as it continues to review the Final Report and meet with First Nations, among other groups. The Minister expects that the government will make a decision on the project by the end of the year.
On October 26, 2017, the Ministry of Energy released Ontario’s revised 2017 Long-Term Energy Plan (“LTEP”), Delivering Fairness and Choice. The previous LTEP was published in 2013 (“2013 LTEP”).
This blog provides a summary of the resources addressed in the LTEP. An accompanying piece found here provides an analysis of the Directives issued by the government to the IESO and the OEB respecting implementation plans by those agencies.
The LTEP highlights that between 2026 and 2035, contracts for over 4,800 MW of wind energy, 2,100 MW of solar energy, and 1,200 MW of hydroelectric generation will expire. In September 2017, Ontario announced the results of the final Feed-in-Tariff (FIT) procurement, totaling 390 contracts for small-scale renewable representing a total capacity of 150 MW.
Currently, there is 4,800 MW of installed wind power capacity. As for solar, Ontario now has about 2,300 MW of capacity online. In 2015, 23% of Ontario’s total generation came from hydroelectric facilities and has about 8,800 MW of installed capacity.
In the LTEP, Ontario confirmed its plan to move forward with the refurbishment of ten nuclear units, four at Darlington and six at Bruce, between 2016 and 2033 as previously outlined in the 2013 LTEP. Refurbishing these 10 units will secure more than 9,800 MW of capacity. The refurbishment of Darlington is expected to inject $90 billion to Ontario’s economy and increase employment by an average of 14,200 jobs annually. As for Bruce Power, the first unit’s refurbishment date was pushed back from 2016 to 2020, which saved $1.7 billion for electricity consumers. The refurbishment of Bruce power is expected to contribute up to $4 billion in the economy and increase employment by an average of 22,000 jobs annually.
The Pickering Nuclear Generating Station will continue to be operated until 2024, saving up to $600 million for electricity consumers, at which time it will be decommissioned.
Innovation and Energy Storage
Since the 2013 LTEP, Ontario has procured 50 MW of different types of energy storage and supported energy storage projects through the Smart Grid Fund. An IESO study published in 2016 found that energy storage facilities can provide essential services to ensure that the electricity system operation is reliable. Ontario has also studied and identified market barriers for energy storage technologies. The LTEP notes Ontario’s plan to update regulations, which includes addressing how the global adjustment is charged for energy storage projects. As part of the LTEP, Ontario has directed the OEB and the IESO to review its rules and regulations that may create barriers for the development of energy storage.
Other initiatives include Ontario’s plan to modernize the grid through a digital grid, which allows customers and utilities to make the right decisions related to consumption of electricity. Ontario is also studying projects in several jurisdictions that are piloting transactive energy and blockchains in order to develop projects of such kind in Ontario. Another project aims at ensuring greater reliability and quality of service for transmitters and distributors in order to improve reliability for consumers. The IESO has been directed by Ontario to develop a competitive selection or procurement process for transmission to identify potential pilot projects. In the LTEP, Ontario is also proposing to expand net metering to allow more homeowners to access energy storage technologies.
Although largely unnoticed at the time, the passage of Bill 135 fundamentally changed energy regulation in Ontario. It created a new planning process centered on the creation and implementation of government-drafted Long Term Energy Plans, or LTEPS. This new process starts with the LTEP and continues on through agency implementation plans that are approved and overseen by the government. It is the most government-controlled energy planning process in Ontario history. This managed approach carries potential benefit: it increases the likelihood that the government may allow plans to be completed, and even followed. In the past, the government abandoned planning initiatives before they were completed.
On the other hand, it also increases the risk that agency developed planning and evaluative criteria will be exercised entirely by and for political decision-making. In other words, if the agencies do not exercise independent judgment in developing implementation plans, and the only goal of the plans is to obtain the government’s approval, the integrity of long term regulatory or planning principles will be diminished, if not lost all together.
The LTEP Directives – The Role of the Government
The change to the planning process is expressed in the directives to the Ontario Energy Board (OEB) and the Ontario Independent Electricity System Operator (IESO).
The LTEP directives require the agencies to prepare implementation plans that cover dozens of issues (16 for the OEB and 15 for the IESO) addressed in the LTEP.
The directives require the agencies to prepare a plan to “include steps that clearly demonstrate” how each of the agencies will “implement the policy reviews, processes and other initiatives enumerated below.” The government emphasizes that it will be in charge of the process:
“The implementation plan should comprehensively detail the key implementation milestones for each initiative, provide sufficient detail on process and timing, and articulate intended outcomes.”
The government will review, approve and amend implementation plans and the agencies are required to follow them.
The LTEP Directives – the Tasks of the Agencies.
The actual list of reviews, etc. in the LTEP directives does not contain too many surprises. They are topics that have been debated in regulatory proceedings and consultations over the last few years.
Some of the issues are ripe for review. For example, there is a requirement for the IESO to review its regional planning to “identify barriers to the implementation of cost effective non-wires solutions such as conservation and demand management and distributed energy resources…” Given the IESO’s preference for transmission solutions, a consideration of whether its approach contains any inherent biases towards those outcomes is a useful exercise.
Other initiatives seem to go over well-trodden ground. For example, the OEB is to identify opportunities for distribution investments and, in doing so, “the Board shall consider the issue of the diffusion of benefits that may arise from these and other distribution-system investments.”
The “diffusion of benefits” argument has traditionally been made by project proponents who claim that the benefits of their proposed products or services are lost on the market place and unappreciated by regulators. Under this theory, both markets and regulation fail to reward good projects because the benefits of a project are too “diffuse” to be captured by either. The Board should therefore correct those market and regulatory failures by requiring consumers to fund these projects through distribution rates.
The OEB has reviewed the “diffuse” benefits of distributed generation on previous occasions, finding that the problems with the benefits are not that they are “diffuse” but that they do not outweigh the costs.
The LTEP directives require the OEB to review this again. It will be interesting to see if the OEB’s answer to the government is the same as it has determined in more formal proceedings. This will be an important test in the new planning process: will the agencies approach the issues by reference to principles that try to represent objective criteria, or will they produce results that the government wants to see? A high degree of transparency will be required to demonstrate integrity in the process. As a start, and at a minimum, all communications between the government and the agencies in developing these plans should be on the public record.
The directives also define problems in a way that avoids more fundamental but politically inconvenient problems. For example, one glaring issue in the sector is the massive over-capacity in resources (both on the supply and conservation side). The LTEP not only fails to address this issue; it denies that the problem exists. One of the oddest components of the LTEP is that, instead of recognizing a surplus, it claims that Ontario’s peak electricity demand for 2017 is 30,000 MW an overstatement of 23% over actual peak demand of 23,000 MW. Because this forecast demand also presented as equaling equal current supply, there is no surplus: supply and demand are in synch. As a result, the problem of over-supply doesn’t exist.
This is also unfortunate because this problem is not being addressed. A good question for consideration is whether centralized decision making is one of the main reasons for over-supply and whether that can be creatively addressed by decentralizing decision making and making resource adequacy a function of load serving entities. But this is not the type of problem that qualifies for a solution under the LTEP.
Another directive requirement is for the IESO and the OEB are to focus on “Innovation in the Sector.”
It would take a level of courage (not to mention self-awareness) of the agencies to advise the government that true innovation would require the sector operating more like a business than a set of government programs. Innovation is likely to occur if customers get to exercise real choice, as opposed to the contrived choices identified by governments and regulators. In other words, there is no room to prescribe an environment where innovation would fail or succeed based on customer’s perception of value instead or regulatory or political arbitrage.
It will be interesting to see how this first post Bill 135 planning process will work. It has the opportunity of bringing some new perspectives on old problems. On the other hand, it brings the risk that the agencies will use their powers in a more political way, favouring a communications narrative over deliberate and transparent decision-making.
As we reported in a blog post in October 2016, the Renewable Energy Approval (“REA”) for the Fairview Wind Farm (“Fairview”) in Clearview Township was revoked by the Environmental Review Tribunal (“ERT”) on the basis that the project would cause serious and irreversible harm to the endangered species of bat, the little brown bats. The ERT also concluded, for the first time, that there would be harm to human health due to close proximity of the project to the Collingwood Airport and the Clairview Field Airport.
The ERT granted a request from Fairview to address remedies with respect to the finding of serious and irreversible harm to the little brown bats through further submissions at a remedy hearing. Fairview did not request such hearing for the finding on harm to human health. In the remedy hearing, the ERT had to determine, under s. 145.2.1(4) of the Ontario Environmental Protection Act (1990) (“EPA”), whether to (a) revoke the decision granting the REA, (b) direct the Director to take such actions as the Tribunal requires in accordance with the EPA or (c) alter the decision granting the REA.
Following the remedy hearing, the ERT released its decision on August 16, 2017 noting that, with regards to the little brown bats, Fairview’s remedy plans would likely reduce little brown bats mortality significantly. However, the ERT ordered that the REA be revoked because Fairview was unable to propose effective means to mitigate the serious harm to human health. In light of this decision, the ERT concluded that an amendment to the REA to include the mitigation plan regarding little brown bats was not necessary.
Given that the Fairview Project decision was the first ERT decision to find harm to human health, it was unclear how Fairview would address remedy through further submissions. In the main hearing, the ERT had considered mitigation measures put forward by Fairview but ultimately decided that there was insufficient evidence that the proposed mitigation measures would be effective. In the remedy hearing, Fairview did not provide additional evidence supporting these mitigation measures nor did it propose new measures. In fact, Fairview did not make any submissions on this issue.
As noted, this was the first ERT decision to revoke an REA based on the finding of harm to human health. In this case, the harm to human health arose from the danger caused by the project’s proximity to the airport, and not from any concerns related to the general impact of wind farms on human health. It will be interesting to see whether this decision will have any impact on human health-related arguments made before the ERT in future REA appeals. The period to file an appeal expired on September 15, 2017.
A pioneering survey has found that Indigenous participation in Canada’s clean energy economy has grown rapidly over the past 20 years, in all regions of the country. Lumos Clean Energy Advisors (Lumos), an advisor to First Nations, Métis and Inuit communities, undertook a review of national research and drew on the company’s database of clean energy projects. In particular, Lumos looked at 152 medium to large-scale solar, wind, hydro and bio-energy clean energy projects now in operation (medium to large projects are categorized as renewable energy projects generating one (1) megawatt of electricity at full operating capacity). The resulting report, Powering Reconciliation: A Survey of Indigenous Participation in Canada’s Growing Clean Energy Economy, highlights the importance of federal and, particularly, provincial/territorial government policies in the areas of energy, climate change and economic development to the rise of Indigenous participation in the clean energy sector. The report also found the following:
- BC leads the way nationally, with 52% of Indigenous clean energy projects in operation, followed by 24% of projects in Ontario and 10% of projects in Québec. The remaining projects are spread across the Maritime provinces, the Prairies and the Territories. An interactive map of projects is available online. The report notes that Saskatchewan and Alberta are now moving into an Indigenous clean energy growth phase. In addition, major growth is anticipated over the next three to five years in over 175 off-grid, remote and northern Indigenous communities as they transition away from diesel-reliant energy.
- Hydroelectric is the most dominant resource for Indigenous renewable energy projects, comprising 63% of all Indigenous clean energy projects. Wind projects are growing and represent 24% of Indigenous clean projects; the remaining 13% of projects are split among three technologies – solar (eight projects in Ontario), biomass (seven projects in BC and one in Québec) and district heating (in Nunavut).
- The generating capacity of clean energy projects with Indigenous partnerships is substantive, totalling 19,516 megawatts, which represents nearly one fifth of Canada’s overall power production infrastructure and $56 billion in capital construction costs.
- Actual equity investment from Indigenous/developer/utility partners ranges from 10-15% of total capital requirements, meaning that the majority of project capital is financed through long-term debt.
- The norm is for Indigenous communities/partners to hold approximately 25% of ownership in clean energy projects. The report estimates that Indigenous communities have invested $1.8 billion in equity in clean energy projects. The source of Indigenous investment varies by project and includes community funds, funds from treaty settlements and land claims, community trusts, debt financing through the project developer, direct grants from the project developer, external borrowing on full commercial terms, and/or external borrowing backstopped by guarantees provided by governments, Indigenous financial institutions or project partners.
- Using project metrics, the report estimates that Return on Investment averaged 14% for projects constructed prior to 2014, 12% for projects constructed from 2014 to the present, and the trend going forward appears to be in the range of 10%.
- Over the next 15 years, Indigenous communities will generate at least $2.5 billion in profit from clean energy project investments.
- Using actual construction employment data from Indigenous clean energy projects surveyed, the report estimates that 15,300 person-years of direct Indigenous employment have been achieved.
- Ancillary benefits from projects include local infrastructure upgrades, community energy literacy and planning, community program support, housing improvements, and cultural features (such as the integration of Indigenous art into clean energy facilities).
- In addition to medium and large-scale projects, over 1,200 small-scale renewable energy projects have been constructed with Indigenous participation.
The report notes that first and foremost, Indigenous communities seek clean energy projects with low to minimal ecological impacts on land, water, fisheries and wildlife. Also, the report notes that clean energy projects with Indigenous participation embody the process of national reconciliation between Canada and Indigenous peoples. In response to the survey, many Indigenous leaders expressed that the most important benefit arising from participation in clean energy projects was a strengthening of community pride and an affirmation of Indigenous rights and territory. In addition, a significant number of Indigenous respondents spoke of the respectful relationships arising through solar, wind, hydro and bio-energy initiatives with project partners, government programs and energy authorities. With an additional 50 to 60 medium to large-scale renewable projects with Indigenous participation expected to come online over the next five to six years, Indigenous engagement in renewable energy projects looks set to continue driving the growth of Canada’s clean energy economy and supporting reconciliation efforts.
With the release of Bulletin 2015-34, the Alberta Energy Regulator (AER) amended the process for transferring pipeline licences to require written confirmation that compulsory records under CSA Z662: Oil and Gas Pipeline Systems and Part 4 of the Pipeline Rules have been maintained by the vendor and transferred to the purchaser prior to the approval of a license transfer. Continue Reading
BC’s recently sworn-in New Democratic Party (NDP) government presented its first provincial budget on September 11, 2017. Among the policy measures announced were changes to the BC carbon tax. In particular, the Budget 2017 Update (2017/18 – 2019/20) provides for the following:
- As of April 1, 2018, the carbon tax will increase by $5 per tonne of carbon dioxide equivalent (CO2e) per year until it reaches the federal target carbon price of $50 on April 1, 2021 (one year before Ottawa’s 2022 deadline). BC’s carbon tax is currently set at $30 per tonne of CO2e.
- Part 2 of the Carbon Tax Act has been repealed, meaning that the requirement for the provincial Minister of Finance to prepare the Carbon Tax Report and Plan will no longer apply after September 11, 2017. In addition, this means that the Carbon Tax Act will no longer require that revenue measures be introduced to offset carbon tax revenues. This will allow the government to spend carbon tax revenues on emission reduction measures or other green initiatives, rather than returning carbon tax revenues to taxpayers.