Canadian Energy Perspectives

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Canadian Energy Perspectives

Record Low Prices: Alberta Releases Results of Round 1 of the Renewable Electricity Program

Posted in Alberta Electric System Operator, Energy – Renewable, Alternative and Clean
Alberta
Kimberly J. Howard

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:

  1. EDP Renewables Canada Ltd. – Sharp Hills Wind Farm (248.4 MW) in Oyen, Alberta
  2. Enel Green Power Canada, Inc. – Phase 2 (30.6 MW) of Castle Rock Ridge Wind Power Plant in Pincher Creek, Alberta
  3. Enel Green Power Canada, Inc. – Riverview Wind Farm (115 MW) in Pincher Creek, Alberta
  4. 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.

Qualified Proponents

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.

Pressing On: B.C. Government Announces Decision to Complete Construction of Site C Clean Energy Project

Posted in BC Hydro, Energy – Renewable, Alternative and Clean
British Columbia
Sven MilelliSelina Lee-AndersenMorgan Troke

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.

Bulletin 2017-21 and Directive 067 Changes to Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals

Posted in Energy – Conventional
Kristen HainesCraig Spurn

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.

Continue Reading

Bulletin 2017-21 and Directive 067 Changes to Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals

Posted in Energy – Conventional, Regulation
Craig SpurnKristen HainesKimberly J. Howard

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

Ontario Energy Association and Association of Power Producers of Ontario Release Report on Energy Governance in Ontario

Posted in Power
Ontario
Zachary Masoud

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.

No Easy Way Out: BC Utilities Commission Issues Final Report Following Site C Inquiry Process

Posted in BC Utilities Commission
Selina Lee-AndersenConnor Bildfell

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:

  1. completing Site C by 2024, as currently planned;
  2. suspending Site C, while maintaining the option to resume construction until 2024; and
  3. 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.

Overview of the 2017 Long-Term Energy Plan

Posted in Ontario Independent Electricity System Operator, Ontario Ministry of Energy, Power, Regulation
Ontario
George VeghZachary MasoudBrianne Paulin

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.

Renewable Energy

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.

Nuclear Power

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.

The LTEP: A Fundamentally New Planning Approach

Posted in Ontario Independent Electricity System Operator, Ontario Ministry of Energy, Power, Regulation
Ontario
George Vegh

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.

Conclusion

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.

ERT revokes renewable energy due to airport impacts

Posted in Energy – Renewable, Alternative and Clean, Power, Renewable Energy Approval
Joanna RosengartenBrianne Paulin

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.

In Pursuit of Sustainable Communities: Survey finds that Indigenous Participation is Driving Clean Energy Growth in Canada

Posted in Aboriginal, Climate Change, Energy – Renewable, Alternative and Clean, Energy Partnerships
Selina Lee-Andersen

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.

Pipeline Records and Purchase and Sale Agreements The Effect of AER Bulletin 2015-34

Posted in Purchase Agreements
Kristen HainesCraig Spurn

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

Changing Tack: BC NDP Accelerates Increase in Carbon Tax and Moves Away from Revenue Neutrality

Posted in Carbon Tax, Climate Change, Climate Policy, Emissions Regulation
British Columbia
Selina Lee-Andersen

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.

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Taking on the Political Hot Potato of Pipelines: BC’s Attorney General Granted Intervenor Status in Federal Court of Appeal Proceeding Challenging Trans Mountain Pipeline Approvals

Posted in Energy – Conventional, Federal
British Columbia
Selina Lee-AndersenConnor Bildfell

The proposed Trans Mountain Expansion Project (the Project) involves a $7.4-billion expansion of the Kinder Morgan pipeline stretching from Edmonton to Burnaby, as well as the construction of new works such as pump stations and tanks and the expansion of an existing marine terminal. In December 2016, the Project received federal government approval, after the National Energy Board (NEB) recommended in May 2016 that the Project should proceed, subject to the satisfaction of 157 conditions. Under the Constitution Act of 1867, the regulation of international and inter-provincial transportation (which includes pipelines) falls within the exclusive jurisdiction of the federal government.

In January 2017, the Project received its provincial environmental assessment certificate along with a political green light to move forward. In expressing the province’s support for the Project, then Premier Christy Clark indicated that the Project had met the five conditions the provincial government had issued in 2012 for approving any pipeline projects. Following the close results of BC’s provincial election in May 2017, the NDP formed a government with the backing of the BC Green Party. In Premier John Horgan’s July 2017 mandate letter to the new Minister of Environment and Climate Change Strategy, George Heyman, the Minister was tasked with employing “every tool available to defend BC’s interests in the face of the expansion of the Kinder Morgan pipeline, and the threat of a seven-fold increase in tanker traffic on our coast”, among other things. This is the context within which the Attorney General of BC (the AG) sought – and was ultimately granted – intervenor status in the upcoming Federal Court of Appeal proceeding challenging the administrative approvals for the Project, discussed in further detail below. Continue Reading

The Final Countdown – AESO Opens Request for Proposal Stage in Round 1 of Alberta’s Renewable Energy Program

Posted in Electricity, Energy – Renewable, Alternative and Clean, Independent Producers, Power, Procurement
Alberta
Kimberly J. Howard

On September 15, 2017, the Alberta Electric System Operator (AESO) announced the opening of the final Request for Proposal (RFP) stage of Round 1 of the Renewable Energy Program (REP).

While an official list of the successful projects and proponents has not been publicly issued, the AESO communicated that it invited 29 qualified projects representing approximately 4,000 MW from Canadian and international companies to participate in the RFP stage. Continue Reading

New China Guidelines on Overseas Investments Encouraging for the Natural Resources Sector

Posted in Energy – Conventional
Shea SmallJoyce LeeBobby WangCraig Spurn

On August 17, 2017, China’s NDRC, Ministry of Commerce, the People’s Bank of China and the Ministry of Foreign Affairs jointly released their Opinions on Further Guiding and Regulating the Directions of Overseas Investments (the “Guidelines”).  The stated objectives of the Guidelines are to improve the macro guidance on overseas investments, further guide and regulate the directions of overseas investments, promote the sustainable, rational, orderly and healthy development of overseas investments, effectively prevent all types of risks and properly meet the needs of national economic and social development. Continue Reading

Canadian Bidders in First Massachusetts Clean Energy RFP

Posted in Electricity, Energy – Renewable, Alternative and Clean, Independent Producers, Power, Procurement
Christopher LangdonHeba Al-Shakarchi

Five Massachusetts-based affiliates of electricity distributors Unitil, Eversource and National Grid (the “Massachusetts Distributors”), together with the Massachusetts Department of Energy Resources (“MDOER”), have reported receiving 46 proposals in response to the ‘Request for Proposals for Long-term Contracts for Clean Energy Projects’ (the “RFP”) they had jointly issued in March 2017. The RFP is one of several initiatives put forward to meet the Commonwealth’s ambitious clean energy goals, most recently promoted by its enactment of the Chapter 188 energy diversity bill in 2016.  Among other matters, the bill mandates that the Massachusetts Distributors enter into long-term contracts for the annual procurement of approximately 9,450,000 megawatt-hours (MWh) of renewable energy from wind, solar, hydro or energy storage sources. Continue Reading

Cap & Trade 2.0: California Fine Tunes and Extends Cap & Trade Program to 2030

Posted in Climate Change, Climate Policy, Emissions Regulation, Emissions Trading
Selina Lee-Andersen

On July 17, 2017, the California legislature passed legislation to extend the state’s cap-and-trade program to 2030 (the program was originally set to expire in 2020).  Bill AB 398 received broad bi-partisan support and was passed with a two-thirds majority vote, which is the threshold required to pass tax laws in California. With a super-majority vote, California’s cap-and-trade program will be harder to challenge in court, thus providing policy certainty to market participants and partner jurisdictions including Québec and Ontario. AB 398 was accompanied by two bills: (1) AB 617, which seeks to address local air quality concerns by requiring increased monitoring, mandating upgrades of outdated equipment and technology, and imposing stricter penalties for noncompliance with regulations; and (2) ACA 1, which establishes the Greenhouse Gas Reduction Fund, into which all revenue from the auction or sale of allowances will be deposited (a 2/3 vote of each house will be required to appropriate the funds). The passage of AB 617 was key to winning over the support of key environmental groups. Continue Reading

Quebec Releases Energy Policy’s 2017-2020 Action Plan

Posted in Energy – Renewable, Alternative and Clean, Hydro-Québec, Québec
Québec
Mathieu LeBlancMartin Thiboutot

On June 26, 2017, Québec’s Energy and Natural Resources Minister, Mr. Pierre Arcand, unveiled the 2017-2020 Action Plan (the “Plan”), a first step towards implementing the 2030 Energy Policy (the “Policy”). The Policy, made public in April 2016 by the Québec Government, sets forth ambitious targets aimed at reducing both Quebec’s consumption of fossil fuels and its dependency on foreign energy, thereby achieving “energetic transition”.

A year later, the Action Plan sets out 42 measures (in French only), backed by $1.5 billion public investments, providing for concrete actions which are divided in four axes: (1) integrating the energetic transition’s governance; (2) fostering energetic transition towards a low-carbon-footprint economy; (3) offering consumers a diversified and renewed energy supply; and (4) defining a new approach with respect to fossil fuels. The implementation can be followed directly on the Action Plan website (in French only). Two of the measures are already in place, while 17 are underway. While much remains to be put into place, the Plan as presented should appeal to the energy industry by creating investment opportunities in Québec, without neglecting environmental targets. Continue Reading

Canada Ratifies Convention on Supplementary Compensation for Nuclear Damage

Posted in Energy – Conventional, Nuclear
Joanna Rosengarten

On June 6, 2017, Canada ratified the International Convention on Supplementary Compensation for Nuclear Damage (the “Convention”). The ratification of this Convention follows the coming-into-force of the Nuclear Liability and Compensation Act (“NLCA”) on January 1, 2017. This domestic legislation was a prerequisite for Canada ratifying the Convention. Canada’s closest neighbor, the United States, ratified in the Convention in 2008. Continue Reading

Alberta Court of Appeal upholds Redwater Decision

Posted in Energy – Conventional, Regulation
Alberta
Kimberly J. Howard

In a majority two to one decision released on April 24, 2017, the Alberta Court of Appeal (ABCA) upheld the lower court ruling in Re Redwater Energy Corporation.  Our discussion and analysis of the trial decision in Redwater, which settled a lengthy conflict between the Alberta Energy Regulator and insolvency professionals on the proper interpretation of section 14.06 of the Bankruptcy and Insolvency Act (Canada), can be found here.

A full discussion of the ABCA decision and its impacts on insolvency-driven transactions involving assets regulated by the Alberta Energy Regulator prepared by our bankruptcy and restructuring colleagues, Sean Collins, Walker W. MacLeod and Pantelis Kyriaskakis, can be found on our Restructuring Roundup Blog.

Ontario Cap-and-Trade Update: Auction, Decision and Proposal

Posted in Climate Change, Emissions Regulation, Emissions Trading
Ontario
Joanna Rosengarten

As Ontario’s Cap-and-Trade Program is now in full swing, we wanted to provide an update on some of the more noteworthy developments.

Quarterly Auction Kick-Off

On March 22nd, 2017, the Ontario Government held the first quarterly auction for emission allowances under the Cap-and-Trade Program. As we previously reported, the Ontario Government indicated that it expects to raise $1.9B yearly from the sale of emission allowances. The first auction generated $472,031,155 in proceeds from the sale of 25,296,367 current allowances sold at $18.08 each, and 812,000 from future vintage allowances sold at $18.07 each. The auction sold 100% of current vintage allowances and 27% of future vintage allowances. Continue Reading

Round 1 of Alberta’s Renewable Electricity Program Opens on March 31, 2017

Posted in Electricity, Energy – Renewable, Alternative and Clean, Independent Producers, Power, Procurement
Alberta
Kimberly J. Howard

Renewable Electricity Program

The Government of Alberta announced that the Alberta Electric System Operator (AESO) will launch the first competition of the Renewable Electricity Program (REP) on March 31, 2017 with a Request for Expressions of Interest (REOI).  Additional details with respect to Round 1 and the REOI stage will be available here on March 31, 2017.

As detailed in a previous blog post with respect to the REP process, the stakeholder comments on the key provisions of the Renewable Electricity Support Agreement (RESA) and the first competition will procure up to 400 megawatts of renewable electricity.

The AESO is hosting an REOI information session at 1:30 p.m. on April 18, 2017 at the Westin Hotel in Calgary, Alberta.  Those wishing to attend may do so in person or via webinar and can RSVP by emailing their attendance preference to rep@aeso.ca.

 

Ending the Cycle of Electricity Price Interventions in Ontario

Posted in Electricity, Power
Ontario
George Vegh

Every decade the government of Ontario freezes or cuts electricity prices because the costs of an ambitious energy policy prove to be politically unacceptable. This leaves future electricity customers paying for the cost of a failed experiment from a previous generation. We should learn from this experience and implement a governance model for the sector that reviews and mitigates costs before a policy is adopted, not after.

In 1993, the government froze prices because the costs of Ontario Hydro’s massive nuclear expansion were leading to double-digit rate increases. In 2002 the government froze prices because the electricity market opening resulted in higher and more volatile prices.  In 2017, the government cut prices because of the cost of the green energy and economy ambitions. In each case, the underlying cost pressures of the policy were obvious and the resulting escalation of prices was entirely predictable, as were the consequences of the price interventions; future generations were made financially responsible for their parents’ policy choices. Continue Reading