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Canadian Energy Perspectives

Ripple Effect Continues: AER Issues Bulletin 2016-16 in Wake of Redwater

Posted in Energy – Conventional
Alberta
Craig SpurnKimberly HowardKimberly Macnab

On Monday, June 20, 2016, the Alberta Energy Regulator (AER) issued Bulletin 2016-16 (Bulletin) detailing its interim regulatory response to the Alberta Court of Queen’s Bench decision in Re Redwater Energy Corporation (Redwater).

As detailed in a previous post, the Redwater decision allows a trustee to disclaim certain assets (and their associated abandonment and reclamation obligations) under the provisions of the federal Bankruptcy and Insolvency Act (BIA).  In doing so, such a trustee will not be liable as a licensee under the provincial oil and gas regulatory regime in relation to the renounced assets.  Further, the trustee is not required to assume any liabilities, and will not be bound by any abandonment orders issued by the AER relating to renounced assets, in seeking approval of the sales process to sell assets remaining under its possession and control.

With respect to the AER’s Licensee Liability Rating Program (LLR Program), the result of Redwater is that the AER cannot consider the disclaimed assets in calculating a company’s Licensee Liability Rating (LLR) for the purpose of approving or refusing a transfer of licences to a purchaser who is subject to a BIA bankruptcy or receivership.  Generally, these impacts all resonate from the court’s finding that the provisions of the provincial legislation governing the actions of licensees of oil and gas assets do not apply to receivers and trustees in bankruptcy of insolvent companies insofar as they conflict with the BIA, as the federal legislation is paramount.

Bulletin 2016-16

The Bulletin confirms that the AER and Orphan Well Association (OWA) have appealed Redwater, and announces three interim regulatory measures to be effective immediately.  According to the AER, the following measures are temporary, pending the earlier of the Redwater litigation or the implementation of appropriate regulatory measures:

1.           Licence Eligibility Approvals

The AER will consider and process all applications for licence eligibility under Directive 067: Applying for Approval to Hold EUB Licences as nonroutine and may exercise its discretion to refuse an application or impose terms and conditions on a licence eligibility approval if appropriate in the circumstances.

2.           Material Changes in Licence Eligibility

For holders of existing, but previously unused, licence eligibility approvals, prior to approval of any application (including licence transfer applications), the AER may require evidence that there have been no material changes since approving the licence eligibility.  This may include evidence that the holder continues to maintain adequate insurance, and the directors, officers and/or shareholders are substantially the same as when licence eligibility was originally granted.

3.           Post-Transfer LLR of 2.0 or Higher

As a condition of transfer of existing licences, approvals, and permits, the AER will require all transferees to demonstrate they will have a LLR of 2.0 or higher immediately following the transfer.

Earlier this year, the AER had issued Bulletin 2016-10 to “remind” licensees and their directors and officers “of their statutory responsibilities when ceasing operations because of insolvency or for any other reason.”  Bulletin 2016-10 specifically noted licensees’ responsibility to obtain AER approval to transfer licences, approvals, or permits to an eligible party with an LLR of at least 1.0 post-transfer, which was increased to a LLR of 2.0 in the new Bulletin.

AER’s Justification for the Bulletin

The Bulletin could have significant and far-reaching impacts to the oil and gas industry and Alberta’s economy, including preventing new licensee entrants, reducing competition for leases, properties and assets, and creating a chilling effect on investment interest.  Notwithstanding these impacts, it is our understanding that the AER felt it was necessary to quickly formulate an interim response to Redwater and as such issued the Bulletin without extensive consultation.

In justifying its regulatory measures, the AER stated the following within the Bulletin:

  • The changes are interim measures to minimize risks to Albertans and the AER intends to work with industry and other stakeholders and the Government of Alberta to develop broader and more permanent regulatory measures in accordance with government policy in response to Redwater.
  • While the AER recognizes that these measures will inconvenience some stakeholders, they are necessary to ensure the continued protection of Albertans and confidence in both the regulatory system and AER licensees; and
  • The post-acquisition minimum LLR of 2.0 was justified on the following basis: (i) it only applies to licensees wishing to acquire AER-licensed assets; (ii) it is required because the AER has observed licensees maintaining a LLR at the minimum level (i.e. 1.0) and purchasing assets, only to find themselves in financial difficulty shortly after the acquisition; and (iii) licensees have a number of ways to achieve a LLR of 2.0 or higher, including posting security, addressing existing abandonment obligations, or transferring additional assets.

What’s Next?

While ensuring that abandonment and reclamation obligations are borne by industry is within the public interest, unilateral strategies and policy changes will only compound the crippling effects on the Canadian oil and gas industry caused by current economic conditions and global oversupply and competition.  The AER appears to have recognized this in the Bulletin by committing to work with industry, stakeholders and the Government of Alberta in developing broader, more permanent regulatory measures in accordance with government policy.

The magnitude of the abandonment and reclamation liabilities in Alberta must be viewed in context in order to fully understand the size and scope of the issue.  The liabilities are magnified through the lens of the AER’s LLR Program, which looks primarily at the licensee/operator of the assets rather than all of the working interest participants.  In contrast, although the licensee/operator is the only party subject to the AER’s LLR Program, the OGCA and operating procedures provide that abandonment and reclamation obligations are shared by all working interest participants.  The vast majority of working interest participants in the province are solvent, viable companies with the financial capacity to fund their abandonment and reclamation obligations.

When viewed in light of the number of parties to whom responsibility can be cast, the magnitude of the risks is not nearly as large as originally perceived.  Changes to the LLR Program for the purposes of casting a wider net would provide a more accurate assessment of the actual risks and liabilities for Albertans.

However, the Canadian oil and gas industry is currently under significant financial hardship, as evidenced by tens of thousands of job terminations, termination of billions in capital spending, 10% rig utilization, and 25% office vacancy rates.  Among other challenges, low commodity prices, lack of access to international markets, competing international resource developments, and new carbon emissions regimes all contribute to a very tough economic environment.  Nonetheless, the oil and gas industry remains a substantial part of the Canadian economy, and it is the backbone of the provincial economy.

In this current period of restricted cash flow, piling additional obligations and financial hardship solely on licensees/operators for abandonment and reclamation liabilities risks the long-term viability of the industry in Western Canada.  While industry must help the AER and provincial government solve the problem of abandonment and reclamation liabilities, an important point that seems to be missing from the debate is that the best way of funding those liabilities is ensuring the continuation of a healthy and robust industry.  Measures to increase the burden on industry for the purpose of addressing abandonment and reclamation liabilities today and in the future must be weighed carefully against ensuring a return to a more robust provincial economy, which benefits all Albertans.

Further, increasing the LLR for transfers to 2.0 while existing licensees must only meet an LLR of 1.0 raises a number of questions, including related to fairness.  While requiring transferees to meet a LLR of 2.0 or greater, the Bulletin does not impose a similar obligation on transferors – presumably there is an equal risk that a transferor’s LLR can dip to 1.0?  Further, we speculate whether, in order to meet the required threshold, the higher LLR for transferees could lead to the disclaimer of more borderline economic, but currently inactive, wells.  What happens if a transferee’s LLR dips below 2.0 post-acquisition – would it be required to take steps to maintain a LLR of 2.0 or greater, or is 1.0 sufficient (as it is for other licensees)?

Clearly the AER and industry ought to be working together to find a long-term and viable solution to the funding and retirement of abandonment and reclamation liabilities.  In fact, we understand that discussions of this nature have begun among the AER, the Explorers and Producers Association of Canada (EPAC), the Canadian Association of Petroleum Producers (CAPP) and potentially others.

The Quebec Government introduces the Petroleum Resources Act

Posted in Québec
Québec
Pierre BoivinPierre RenaudDominique Amyot-BilodeauMartin Thiboutot

On June 7, 2016, the Quebec Minister of Energy and Natural Resources, Mr. Pierre Arcand (the “Minister“) introduced Bill No. 106 at the National Assembly (An Act to implement the 2030 Energy Policy and to amend various legislative provisions) (the “Bill“). Among other things, this Bill would enact the new Petroleum Resources Act in replacement of the existing provisions of the Mining Act (CQLR c M-13.1) that currently regulate hydrocarbons mining activities in the province.

This Bill had been expected for several months and would significantly modify the legal framework applicable to the development and production of hydrocarbons in Quebec. It purports to govern the development of petroleum resources in the province of Quebec while ensuring the safety of persons and property, environmental protection, and optimal recovery of the resource. The bill also aims at ensuring that mining work involving hydrocarbons is performed in compliance with the greenhouse gas emission reduction targets set by the Quebec Government. Continue Reading

The Quebec Government introduces its Bill to Modernize the Environmental Authorization Scheme

Posted in Québec
Québec
Dominique Amyot-BilodeauCindy Vaillancourt

On June 7, 2016, the Quebec Minister of Sustainable Development, Environment and the Fight against Climate Change, Mr. David Heurtel (the “Minister“), introduced Bill 102[1] at the Quebec National Assembly, which aims at modernizing the environmental authorization scheme established by the Environment Quality Act. If adopted in its current form, this bill could have important repercussions on the environmental assessment procedure and on the authorization scheme of industrial projects carried out in Québec. Continue Reading

Quebec Government Introduces Legislation Implementing its 2030 Energy Policy

Posted in Plan Nord, Québec, Régie de l’énergie, Regulation
Québec
Daniel BénayMathieu LeBlancMason Gordon

On June 7, 2016, the Quebec Government introduced before the National Assembly Bill 106, An Act to implement the 2030 Energy Policy and to amend various legislative provisions. The 2030 Energy Policy has the principal goal of making Quebec, by 2030, a North American leader in renewable energy and energy efficiency. Continue Reading

What Every Stakeholder Needs to Know About Lobbyist Registration

Posted in Energy – Conventional, Energy – Renewable, Alternative and Clean, Federal
AlbertaBritish ColumbiaOntarioQuébec
Mathieu LeBlanc

The following article published in our firm’s newsletter could be of interest to many readers active in the energy industry across Canada. It discusses the applicable rules for lobbyist registration in Ontario, Ontario municipalities, Québec, British Columbia, Alberta and at the federal level. Continue Reading

When the Levy Breaks: Alberta Government Tables the Climate Leadership Implementation Act

Posted in Carbon Tax, Climate Change, Climate Policy, Energy – Renewable, Alternative and Clean
Alberta
Kimberly HowardSelina Lee-AndersenKimberly Macnab

On May 24, 2016, Alberta’s provincial government tabled Bill 20 for first reading in the legislature.  Otherwise known as the Climate Leadership Implementation Act (Climate Act), Bill 20 furthers the implementation of the provincial government’s Climate Leadership Plan released in November 2015.

Bill 20 provides for a carbon levy on consumers of fuel, and creates an agency called Energy Efficiency Alberta, as part of the provincial government’s ongoing commitment to climate change policies and initiatives.   Notably absent from Bill 20 are any details on initiatives or incentives for transitioning to renewable energy sources.

More information on this development may be found on McCarthy Tétrault’s Canadian ERA Perspectives blog.

Ontario Energy Agency Could Correct Province’s Past Policy Mistakes

Posted in Climate Change, Emissions Regulation, Ontario Ministry of Environment
Ontario
George Vegh

The Ontario government’s proposed creation of an agency with a mandate to reduce carbon emissions by buying offsets, funding cleaner factories and buildings, and co-ordinating rooftop solar and energy conservation has been met with skepticism, particularly in light of the province’s experience with energy agencies.   However, there is also reason for optimism.  Read the whole article here.

The AESO’s Renewable Electricity Incentive Program Marches Forward

Posted in Climate Policy, Electricity, Energy – Renewable, Alternative and Clean, Power, Procurement, Utilities
Alberta
Kimberly MacnabKimberly Howard

As noted in an earlier post, on March 3, 2016, the government announced that the Alberta Electric Systems Operator (AESO) has been chosen under the province’s Climate Leadership Plan to develop and implement a renewable electricity incentive program (Renewable Electricity Program or REP) to add additional renewable generation capacity into Alberta’s electricity system.

The expected timeline of this process is as follows:

Q1-Q2 2016

Phase 1 of stakeholder engagement process closed on March 24, 2016.

May 2016

Provincial government has requested AESO’s draft recommendations on program design.

Q2-Q3 2016

Program development.

Q4 2016

First competition for new REP projects.

Q2 2019

Expected in-service date of first REP projects.

On May 5, 2016, the AESO released an update of the stakeholder engagement process and the development of its recommendations to be provided to the provincial government in the next month (Update to Stakeholders).

In its Update to Stakeholders, the AESO summarized the stakeholder feedback received in Phase 1 of the stakeholder engagement process, and commented on its next steps.

Next Steps

The next step of the AESO’s process will involve targeted, one-on-one follow-up meetings over the next few weeks with those parties whose responses may potentially impact the AESO’s recommendation respecting the REP design, and which may inform key features of the first procurement under that program.

The AESO also provided a few details that are expected (although not yet governmentally approved) to delineate the scope of the first REP procurement, namely:

  • The definition of “renewable” is anticipated to align with the definition used by Natural Resources Canada.
  • The procurement is anticipated to be fuel-neutral.
  • Facilities may be expected to be in-service in 2019.
  • It is anticipated that the existing transmission system will be leveraged.

The AESO plans to release information respecting contractual provisions for the first procurement in the fall of this year, and noted its commitment to ongoing engagement with industry on subsequent REP procurements and updates on the REP.

Phase I Stakeholder Feedback

Stakeholders self-identified into one of three main categories: (i) developers/investors; (ii) associations and environmental public policy groups; and (iii) others (which included a Transmission Facility Owner, and ancillary service  providers and manufacturers, among others).  Most of the feedback summarized by the AESO was garnered from developers/investors.

Further Information Needed

Respondents indicated that more information was needed in a number of areas prior to making a decision to invest in Alberta.  This included clearer regulatory processes for specific fuel types, and more information on the coal retirement schedule, as well as defined procurement and overall renewable development targets.

The definition of “renewable” was also requested, which the AESO has noted in this update will parallel the definition used by Natural Resources Canada.  Other key informational gaps included information on existing transmission capacity and areas of constraint, which is of particular importance to wind development in southern Alberta, given existing system constraints and plans to continue transmission reinforcement in the region.

Investment Considerations

Respondents also provided information on their opinions as to key considerations and barriers to investing in renewable energy projects, and noted, among others, the current power pool prices in combination with the capital-intensive nature of renewable energy projects.  Other issues included work already underway on the coal phase-out schedule, changes to the carbon pricing regime and market prices, as well as regulatory and interconnection timelines, and clarity about the level of support being provided.  Another key issue identified was the ability to obtain financing at attractive rates.

Barriers to Energization by 2018

There are a number of projects currently advancing through the AESO’s connection queue which have the potential to achieve energization by the end of 2018.  However, the AESO noted that most developers found that 2018 is a challenging timeline based on a number of factors, including: (i) conducting environmental studies and obtaining environmental permitting; (ii) obtaining interconnection and other regulatory approvals; (iii) obtaining financing or the potential for financing delays; (iv) conducting procurement and construction for larger projects; and (v) the visibility of the coal phase-out schedule.

Recommendations to Address Investment Considerations

  • The provision of financial support which could take a variety of forms (i.e., capped/uncapped REC, contract for differences, power purchase agreement, feed-in-tariff agreement, government financing etc.).
  • The introduction through the REP of carve-outs (i.e. for specific fuel types, to advancement other socio-economic objectives).
  • Greater clarity with respect to the long term plan / schedule for the procurement of renewable electricity generation, in addition to any short and long term targets.
  • Greater clarity with respect to the coal phase-out schedule.
  • Exploring whether there may be options to build renewable energy projects on public land.
  • Making transmission modelling/transmission capacity information with respect to the grid available.

Stakeholder Comments on Timelines

Finally, the expected timelines for different resources were provided by stakeholders as 4-6 years for wind, 1.5-3 years for solar, 2-3 years for biomass, 3-7 years for geothermal, and 10-14 years for large hydro projects.

Conclusions

It is clear from the AESO’s summary of stakeholder feedback that renewable energy developers are still missing information which will affect investment decisions in the province.  Many similar themes appear to have arisen throughout the consultation process, chief among them being the lack of certainty and visibility surrounding the province’s climate change plans such as incentive programs and the coal phase-out.

As the AESO’s mandate letter for developing the REP states that the AESO must prepare a plan for review and consideration by the provincial government no later than May 2016, observers can expect a significant increase in the information available on the proposed form of the REP in the near future.  Stay tuned.

Sign of the Times: 177 Nations (and counting) Ink the Paris Climate Agreement while the World Bank and IMF Push for Carbon Pricing

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

As recently reported on our Canadian ERA Perspectives blog, the Paris Agreement was opened for signature on April 22, 2016 at the United Nations (UN) Headquarters in New York. The Paris Agreement, which was adopted by the parties to the United Nations Framework Convention on Climate Change (UNFCCC) on December 12, 2015, will remain open for signature until April 21, 2017.

As of April 29, 2016, 177 countries had signed the Paris Agreement, 15 of which had also deposited instruments of ratification. Canada is expected to ratify the Paris Agreement in 2016 along with Australia, Argentina, Cameroon, China, France, Mali, Mexico, the Philippines and the United States. The Paris Agreement will enter into force on the thirtieth day after the date on which at least 55 parties to the UNFCCC accounting in total for at least an estimated 55% of the total global greenhouse gas emissions have deposited their instruments of ratification, acceptance, approval or accession with the UN Depositary.  While the United States and China issued a joint statement on March 31, 2016 pledging rapid accession to the Paris Agreement, the two nations represent approximately 38% of global emissions. This means that other significant emitters and a number of additional nations will be needed to meet both the emissions and number thresholds that will bring the Paris Agreement into force.  Entry into force could happen as early as 2017 or 2018, but given the varying timelines for countries to complete their domestic approval processes, the timing of entry into force is uncertain at this time. The World Resources Institute has unveiled its Paris Agreement Tracker, an interactive tool which enables users to monitor countries’ progress toward ratifying the Paris Agreement.

In related climate change policy news, the World Bank and International Monetary Fund (IMF) have created a Carbon Finance Unit that will provide financial and technical assistance to countries that are creating carbon pricing systems.  Leveraging their economic and technical expertise, the World Bank and IMF will work together with developing countries to help them create carbon pricing systems. To date, the World Bank has given an $8 million dollar grant to China, which is developing what is expected to be the world’s largest cap-and-trade program. South Africa and Chile have also received similar grants from the World Bank. The IMF is advising countries on how best to introduce carbon pricing as a means to generate revenue while simultaneously reducing their GHG emissions.

On April 21, 2016, the World Bank, IMF, Organization for Economic Cooperation and Development and the heads of state of Canada, Chile, Ethiopia, France, Germany and Mexico released a statement calling for more carbon pricing.  The goal is to reach enough countries to cover 25% of the world’s GHG emissions by 2020 and 50% of emissions by 2030.

Ontario Court of Appeal rules OEFC changes to calculation of price adjustment index breach the terms of power purchase agreement

Posted in Electricity, Independent Producers, Power, Purchase Agreements
Ontario
Héloïse Apestéguy-ReuxLynn ParsonsJustin Shoemaker

On April 19, 2016, the Ontario Court of Appeal released its decision in Iroquois Falls Power Corporation v. Ontario Electricity Financial Corporation. The decision concerned a dispute between several non-utility generators (“NUGs”) and the Ontario Electricity Financial Corporation (“OEFC”) over changes to a price adjustment index contained within the long-term contracts for the purchase of electricity generated by the NUGs.

This change affected a component portion of a measure known as Total Market Costs (“TMC”), which measure was used to derive the price adjustment index. At the heart of the dispute was an issue of contractual interpretation—whether or not the terms of the power purchase agreements (“PPAs”), and in particular, the price adjustment indices contained within them, required the calculation of the component portion of the TMC to reflect the actual costs of providing existing and new electricity generation. Continue Reading

Court Dismisses Appeal Related to the Darlington Nuclear Refurbishment

Posted in Energy – Conventional, Nuclear, Projects
Ontario
Joanna Rosengarten

On April 13, 2015, the Federal Court of Appeal dismissed the appeal related to the environmental assessment (“EA”) for the refurbishment and continued operation of the Darlington Nuclear Generating Facility (the “Project”). The appeal was from the Federal Court’s earlier decision dismissing a judicial review application related to the EA for the Project. Continue Reading

Phase I of Ontario’s Large Renewable Procurement Process Concluded

Posted in Electricity, Energy – Renewable, Alternative and Clean, Ontario Independent Electricity System Operator, Power, Procurement, Projects
Ontario
Christopher Zawadzki

The Independent Electricity Systems Provider (IESO) has announced that the 16 contracts offered on March 10, 2016 for Phase I of the Large Renewable Procurement process (LRP I) have now been signed and executed. The execution of the contracts concludes the LRP I process. Moving forward, contracted projects will be required to obtain all necessary licenses and approvals before they can be constructed and operated. These processes are separate from the IESO’s procurement activities and will involve additional community engagement. Continue Reading

Ontario Launches Phase II of the Large Renewable Procurement Process

Posted in Electricity, Energy – Renewable, Alternative and Clean, Ontario Independent Electricity System Operator, Ontario Ministry of Energy, Power, Procurement, Project Finance
Ontario
Christopher Zawadzki

The Ontario Ministry of Energy has announced the launch of the second phase of the Large Renewable Procurement (LRP) process (LRP II). The LRP is a competitive bid process for procuring large renewable energy projects in Ontario larger than 500 kilowatts. Continue Reading

Québec’s New Energy Policy

Posted in Québec Hydro-Québec, Régie de l’énergie
Québec
Daniel BénayThomas LavierJacob StoneGrégory Larroque

The Québec Government has unveiled its energy policy for 2016-2030, entitled “Politique énergétique 2030, L’énergie des Québécois – Source de croissance” (Energy Policy 2030, The Energy of Quebecers – a Source of Growth). The policy is the result of two major public consultations that took place in 2013 and 2015. It follows the previous policy in effect from 2006 until 2015 and aims to set out a clear vision of energy development in Québec as well as addressing the concerns of certain stakeholders. Continue Reading

Politique énergétique 2030 du Québec (in French)

Posted in Projects, Québec, Québec Hydro-Québec, Régie de l’énergie
Québec
Daniel BénayThomas LavierGrégory LarroqueJacob Stone

This article will be translated to English shortly.

Le gouvernement québécois a dévoilé aujourd’hui sa politique énergétique pour la période 2016-2030, intitulée « Politique énergétique 2030, L’énergie des Québécois – Source de croissance ». La Politique est le fruit de deux consultations populaires importantes qui ont eu lieu en 2013 et en 2015. Elle intervient à l’expiration de la politique précédente (2006-2015) et vise à énoncer une vision claire du gouvernement en matière de développement énergétique et à répondre à certaines préoccupations contemporaines. Continue Reading

Phasing Out Coal: Alberta Names the Coal Facilitator

Posted in Climate Change, Climate Policy, Coal, Emissions Regulation, Energy – Conventional, Power
Alberta
Kimberly HowardKimberly Macnab

On March 16, 2016, the Government of Alberta finally named the coal facilitator, and announced the next steps for its plan to phase-out coal by 2030.  The province appointed Terry Boston to act as the province’s independent coal phase-out facilitator, and released details of Boston’s mandate and next steps.

Boston’s Prior Experience

Boston is the recently retired CEO of PJM Interconnection (PJM), which is a regional transmission organization in the United States.  PJM controls approximately 105,502 km of transmission lines and manages 186,000 MW of generation serving 61 million people.

Boston has been involved with energy initiatives around the world, including consultation with White House staff and Congress, and has testified before the Federal Energy Regulatory Commission, and served on a number of corporate boards within the electricity industry.  Boston is a recognized expert in grid reliability and transmission.

Purpose of the Facilitator

Boston is tasked with presenting options to government that will strive to maintain the reliability of Alberta’s electricity grid, maintain stability of prices for consumers, and avoid unnecessarily stranding capital.

Desired Outcomes of the Facilitation Process

The desired outcomes are those which have been iterated in the Climate Leadership Plan, namely, that by 2030, two-thirds of Alberta’s coal generation capacity will be replaced by renewable energy, and one-third will be replaced by natural gas.  The provincial government has repeatedly promised that “throughout this process, government will ensure that workers, communities and affected companies are treated fairly.”

Facilitator’s Approach and Deliverables

One key aspect of Boston’s work is that he will engage with the three coal-fired generators who are currently operating units beyond 2030, with the support of Alberta Energy’s Coal Secretariat and the Alberta Electric System Operator.

Because twelve of Alberta’s eighteen coal-fired generating units are expected to shut down prior to 2030 under the current federal regulations, the facilitator’s mandate is focused on the six generating units remaining after 2030.  As set out in the previously released Fact Sheet on the coal phase-out, this will entail discussions with Capital Power, TransAlta, and ATCO Power about the Keephills 3, Genesee 1, 2 & 3, and Sheerness 1 & 2 thermal generating units.

What’s Next?

In addition to consultation with affected generators, the government is also engaging in a parallel process of consultation with the goal of ensuring ongoing support for coal communities and workers.  More announcements on the next stage of these consultations are expected in the next month.

In another recent announcement, the March 8, 2016 Speech from the Throne touched on the implementation of climate change initiatives, noting that one of the elements of “investing in a clean energy future” will be a Climate Leadership Implementation Act, designed to put the Climate Change Plan into action.  Further detail on this legislation, and what it may mean for Albertans, is still up in the air.

 

BC Hydro Releases Long-Anticipated Updates to Standing Offer Program and Introduces Micro-Standing Offer Program

Posted in BC Hydro, Electricity, Energy – Renewable, Alternative and Clean, Independent Producers, Procurement, Purchase Agreements
British Columbia
Ainslie HurdSebastian NishimotoSven Milelli

Updates to the Standing Offer Program (SOP)

On March 4, 2016, BC Hydro released a new version (Version 3.1) of its SOP Rules to address feedback it received during First Nation and stakeholder consultation meetings and focus group discussions conducted over the last few years. The SOP offers small-scale, clean energy projects in British Columbia with capacities between 100 kW and 15 MW the opportunity to enter into energy purchase agreements (EPAs) with BC Hydro. An EPA requires the project developer to sell all energy from the project to BC Hydro for a term of 20 to 40 years commencing on commercial operation date (COD).
Version 3.0 of the SOP Rules introduces several notable changes:

  • Key vs. Standard Eligibility Requirements – eligibility requirements have been reorganized into key eligibility requirements and standard eligibility requirements, with key eligibility requirements serving as an initial threshold within the SOP review process.
  • Annual Energy Volume Target – the developer’s target COD must be in a year where there is sufficient room available in BC Hydro’s annual SOP energy volume target (currently set at 150 GWh/year). This new target volume management system is designed on a first come, first served basis. If the energy volume target for a year has been met, a project will be deferred until the next year with available volume.
  • Public Utility Customers – customers of public utilities other than BC Hydro cannot apply under the SOP, except for customers that take only back-up or start-up electricity service from that public utility.
  • Additional Generators – new generators added to sites with existing generation are no longer eligible under the SOP.
  • Customer-Based Generation – a simplified rule for projects behind a BC Hydro customer load allow these projects to apply under the SOP but BC Hydro will only purchase energy on a net-of-load basis.
  • First Nations Consultation – BC Hydro now considers the issuance of land tenure, permits and licenses as sufficient evidence that a Crown agency has completed its First Nations consultation.
  • Conflicts of Interest Rule – pursuant to a new conflicts of interest rule, a developer must not be in or have the potential to be in an actual, apparent or deemed conflict of interest as a result of entering into an EPA with BC Hydro.
  • Cluster Rules – revised rules regarding project clusters and common generation facilities clarify that such arrangements are permitted but must not exceed 15 MW in the aggregate.
  • Pre-Application Meetings – pre-application meetings remain optional but are strongly recommended. There is a focus on providing eligibility and cost information as early as possible in the development process.
  • Staged Review Process – SOP application and review processes are now organized into stages – BC Hydro will undertake an eligibility assessment before it requests a system impact study (previously referred to as an interconnection study). Rigid timelines for EPA offer and acceptance have been replaced with the more general requirement that such steps occur “within a commercially reasonable period of time”.
  • Changes to EPA – the Standard Form EPA has been streamlined, and now contains only three appendices instead of 12. Other changes to the Standard Form EPA include:
    • clarification that BC Hydro is not obligated to accept delivery of power in excess of the specified hourly energy limits;
    • the requirement, as a condition to COD, that a Project must have generated energy for 54 hours during a period of 72 continuous hours; and
    • the reference to First Nations consultation depending on evidence of Aboriginal claims under section 35 of the Constitution Act, 1982.

The New Micro-Standing Offer Program (Micro-SOP)

On March 4, 2016, BC Hydro introduced the Micro-SOP, which is designed for very small-scale clean energy projects in British Columbia with capacities between 100 kW and 1 MW. The Micro-SOP is only available to First Nations and communities, including municipalities, not-for-profit groups, all organizations of the public and agricultural sectors.

To participate in the Micro-SOP, a First Nation must show that it has significant beneficial ownership of, and will actively participate in, the project. A community group must provide evidence that it has at least 50% control and beneficial ownership of the project. Provided that they satisfy these beneficial ownership requirements, First Nations and community groups are still eligible for Micro-SOP if they partner with private sector independent power producers to develop the project. As with the SOP, there must be sufficient room in BC Hydro’s energy volume target of 150 GWh/year at the time of the Micro-SOP application.

The Micro-SOP differs from the SOP in certain key respects:

  • Non-BC Hydro Utility Service Areas – projects located within another utility’s service territory or jurisdiction, such as the FortisBC service area, are not eligible.
  • Cluster Rules – project clusters and common generation facilities are not eligible.
  • Time of Delivery Price Adjustments – there are no time of delivery price adjustments.
  • Smart Meters – smart meters for measuring energy output and/or consumption are to be used wherever possible.
  • Interconnection – all projects must be directly interconnected to BC Hydro’s distribution system.
  • Standard Form Agreements – the standard form interconnection agreement and EPA are simplified.
  • Screening Studies – there is a mandatory screening study which estimates the interconnection requirements for the project (subject to a $5,000 fee).
  • EPA Term – the EPA term is 5 to 40 years from COD of the project.

First Phase of Water Sustainability Act Comes into Force

Posted in Water
British Columbia
Selina Lee-AndersenMonika Sawicka

The British Columbia Government has finally brought into effect portions of the long awaited Water Sustainability Act (WSA). The WSA, which was passed by the British Columbia Legislature in April 2014, came into effect on February 29, 2016. The WSA replaces many parts of the old Water Act and creates a new regulatory regime for water management within British Columbia.

The Province is taking a phased approach to the enactment of the WSA. While the majority of the WSA came into effect at the end of February, Section 18, which provides for quick licensing procedures, has yet to be brought into force. The Province predicts the next phase of the regulations and policies will be brought into effect in late 2016. This phase will include regulations relating to measuring and reporting, livestock watering, water objectives, planning and governance.

One of the biggest changes that the WSA makes is to the regulation of groundwater. Under the WSA, all groundwater users (except domestic wells) will require a water licence to divert water from an aquifer (unless the diversion is otherwise authorized under the regulations).

Groundwater licence applications can be submitted through FrontCounter BC. The new Ground Water Protection Regulation provides for a comprehensive framework respecting groundwater and deals with: well drillers and well pump installers; well construction; well caps and covers; well pumps and related works; well identification; well operation and maintenance; artesian flow; well deactivating and decommissioning; and well reports.

The Water Sustainability Regulation is also significant as it sets the scope and requirements for the new WSA regimes surrounding: licensing, diversion and use of water; changes in and about a stream; short term diversion of use of water for well drilling; and use of deep groundwater.

While it is unclear exactly how this new water management regime will be implemented by the Province, project proponents requiring water approvals, should seek advice on how the regulations will affect their operations.

LRP I Results

Posted in Community Projects, Ontario Independent Electricity System Operator, Power, Procurement, Project Finance, Projects
Ontario
Christopher Zawadzki

Today, the Independent Electricity Systems Operator (IESO) announced the results of the Large Renewable Procurement (LRP) I program. The LRP is a competitive bid process for procuring large renewable energy projects in Ontario generally larger than 500 kilowatts.

In response to 103 proposals received, the IESO offered 16 contracts representing 454.885 megawatts (MW) of renewable energy capacity. Of the successful proposals, 13 projects representing 336.8 MW include participation from one or more Aboriginal communities, including 5 projects with greater than 50% participation. More than 75% of the awarded proposals had received support from local municipalities with more than 60% support from abutting landowners. Continue Reading

It’s Official – AESO Requests Stakeholder Feedback on Implementation Plan for Alberta’s Renewable Electricity Program

Posted in Climate Change, Climate Policy, Electricity, Energy – Renewable, Alternative and Clean, Power, Procurement, Utilities
Alberta
Kimberly Howard

On March 3, 2016, the Government of Alberta took its first step in implementing the Climate Leadership Plan by officially announcing that the Alberta Electric System Operator (AESO) has been chosen to develop and implement a renewable electricity incentive program for the procurement of renewable generation capacity by 2030 (Renewable Electricity Program). In delivering this mandate, the Province confirmed:

  • The Renewable Electricity Program will be implemented through a competitive process to keep costs as low as possible;
  • The process is to be carefully managed and will operate in concert with the retirement of coal generating units; and
  • Its choice not to fundamentally alter Alberta’s current energy-only wholesale market structure.

Next Steps

The AESO was directed to prepare and provide a draft plan with its program design recommendations to the Government of Alberta no later than May 2016.  Stakeholder engagement has commenced, and developers, investors and other interested parties are invited to visit www.aeso.ca/rep to provide input on the structure of the Renewable Electricity Program.  The deadline for responses is March 24, 2015.

Following receipt of submissions, the AESO will provide its draft recommendations and plan to the Government of Alberta by its May deadline.  It is expected that the first competition will launch in the fourth quarter of 2016, and the first projects will be in service by 2019.

ERT Allows Another Appeal of a Wind Farm Approval

Posted in Energy – Renewable, Alternative and Clean, Renewable Energy Approval, Wind
Ontario
Bryn GrayJoanna Rosengarten

The Environmental Review Tribunal (“ERT” or “Tribunal”) has granted an appeal of a Renewable Energy Approval (“REA”) issued to wpd White Pines Wind Incorporated for its 27 turbine White Pines Wind Project in Prince Edward County (see case 15-068 Hirsch V. Ontario (MOECC) dated February 26, 2016). The ERT concluded the project would cause serious and irreversible harm to two species at risk, the Little Brown Bat and the Blanding’s Turtle. While this is the third REA appeal granted by the ERT, it is the first time that it has found a wind project would cause serious and irreversible harm to bats and this could have significant implications for future projects. Continue Reading

Focus on Environmental Law, from Canadian Power: Key Developments in 2015/Trends to Watch for in 2016

Posted in Climate Change, Climate Policy, Emissions Regulation

As part of our continuing series of blog posts highlighting specific topics addressed in our publication Canadian Power: Key Developments in 2015 /Trends to Watch for in 2016, we focus here on our analysis of developments and anticipated trends in Environmental Law across the country that will impact the power sector.

The National Power Group at McCarthy Tétrault LLP recently released Canadian Power: Key Developments in 2015 /Trends to Watch for in 2016.  This publication provides an unprecedented overview of the most significant developments in the Canadian power industry and to highlight key trends to watch for.  In addition to providing a detailed review of developments in each region, this publication looks at developments in key areas of national scope, including project finance, environmental, regulatory and aboriginal law matters.

Focus on Aboriginal Law, from Canadian Power: Key Developments in 2015/Trends to Watch for in 2016

Posted in Aboriginal, Energy – Renewable, Alternative and Clean

As part of our continuing series of blog posts highlighting specific topics addressed in our publication Canadian Power: Key Developments in 2015 /Trends to Watch for in 2016, we focus here on our analysis of developments and anticipated trends in Aboriginal Law across the country that will impact the power sector.

The National Power Group at McCarthy Tétrault LLP recently released Canadian Power: Key Developments in 2015 /Trends to Watch for in 2016.  This publication provides an unprecedented overview of the most significant developments in the Canadian power industry and to highlight key trends to watch for.  In addition to providing a detailed review of developments in each region, this publication looks at developments in key areas of national scope, including project finance, environmental, regulatory and aboriginal law matters.

Learning from Mistakes: Improving Governance in the Ontario Electricity Sector

Posted in Electricity, Power
Ontario
George Vegh

Over the last 10 years, the government has directed the expenditure of billions of dollars of public money on electricity projects with virtually no oversight or checks and balances. During this time, Ontario consumers have seen a large increase in electricity prices, with more to come.

In response to concerns about the rising cost of electricity and poor governance, the Ontario government has touted its proposed Bill 135 as the solution. However, far from solving the concerns about electricity-sector governance, the proposed Bill entrenches and expands the status quo and provides no role for oversight of government electricity directives.

The provincial government should move away from controlling electricity planning and instead leave the acquisition of supply to those who are responsible to meet fact-based demand requirements or, in the alternative, the government should only set broad policy objectives and not make choices on which technologies and which suppliers should receive government contracts.

See our full analysis here.