Article Detail



Article

Renewable Generation Incentives in Alberta
Contracts for Differences: The Way Forward?

Date

November 2, 2016


Download the article's PDF

A. Background

On November 22, 2015, Alberta released its Climate Leadership Plan outlining a number of key steps for the purpose of reducing greenhouse gas emissions in the province.[1] One such step is the planned phase-out of coal-fired electricity generation by 2030, to be replaced with two thirds renewable energy generation and one third natural gas generation. In order to effect this plan, the Alberta government has promised to offer incentives for renewable generation.

Initially, the provincial government offered little detail on how these renewable generation goals would be accomplished beyond stating that it “will accomplish its transition with policies that fit Alberta’s unique energy market [and] ensure that the electricity system continues to be reliable.”[2] Since then, certain concrete steps have been taken to facilitate the integration of renewable generation sources in Alberta.

On March 3, 2016, the Alberta Electric Systems Operator (AESO or ISO) was directed to develop and implement a renewable electricity incentive program for the procurement of renewable generation capacity by 2030 (Renewable Electricity Program or REP).

Then, on September 14, 2016, the government announced its firm target that 30% of electricity used in Alberta will come from renewable sources such as wind, hydro and solar by 2030. In order to achieve this, the Province intends to support 5,000 MW of additional renewable capacity.

In delivering the AESO’s REP mandate, the Province confirmed that:

  • the process will be carefully managed and will operate in concert with the retirement of coal generating units; and
  • Alberta’s current energy-only electricity market structure will not be altered.

In providing an update on its stakeholder consultation process on May 5, 2016, the AESO released a few details on the scope of the first REP procurement process:

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

The AESO prepared a draft plan and its program design recommendations, which were developed following initial stakeholder input.[3] The AESO delivered its draft plan to the provincial government in May 2016. To date, the AESO’s draft plan has not been made public, and neither the government nor the AESO has released a definitive public statement on what tool or tools will be used to incentivize generation in the new program.

The ball is now in the court of Alberta’s energy ministry, Alberta Energy, and the AESO. The public waits for the government to review the program design recommendations and to develop the regulatory strategy. The anticipated timeline calls for the launch of the first REP competition in Q4 of 2016 in order to have the first REP projects in service by Q2 of 2019. A timeline of only two and a half years for the June 2019 in-service date is quite aggressive, and in our view will require the necessary foundation to make it successful.

Based on our experience in other provinces of Canada and jurisdictions outside the country, a possible program design for Alberta’s deregulated, energy-only market that would meet the Province’s stated objectives is the use of “Contracts for Differences” (CFDs). CFDs backed by government or similarly strong credit ratings have been successfully used to procure generation capacity by closing the gap between a market price that will not support the risk of constructing new generation and a contract price that will.

The purpose of this legal update is to provide an overview of CFDs and some of their potential provisions in order to provide insight into one mechanism that could be used to facilitate the REP in Alberta. We illuminate some of the key issues that government and investors should consider in analyzing such mechanisms, as such issues could be equally applicable to alternative mechanisms for attracting renewable generation investments.

B. Alberta’s Market for Electricity: Pool Price

In Alberta, power generation is deregulated. Power supplied by generators is purchased by users and exporters on a bidding system operated by the AESO. The electricity market has no payment for capacity, only for energy. As such, it is a real-time, energy-only, competitive wholesale market or “power pool”.

The prices in Alberta’s power pool are set at the intersection of supply and demand in real time every minute. Generators may offer, and load may accept, electricity at prices as low as $0/MWh and as high as $999 per megawatt hour until supply is matched with demand. Historically, wind generation facilities were an exception due to their intermittent nature and were not permitted to offer production at a price other than $0/MWh. New ISO rules came into force on April 1, 2015, allowing pool participants with wind aggregated generating facilities to offer energy into the power pool at prices greater than $0/MWh, and compelling these facilities to maintain accurate available capability through submissions to the AESO’s Energy Trading System (ETS). ISO rules for solar facilities are being developed by the AESO and are expected to be released for public consultation in 2017.

Generators offer their electricity supply to the power pool through the ETS one week ahead of the delivery hour (also called the settlement interval). Generators may change the volume of electricity they have offered through the ETS at any time, provided they have an acceptable operational reason to do so, and can change the price up to two hours ahead of the settlement interval. For each hour of the day, offers are sorted from lowest to highest, creating a list called the “merit order”. As electricity demand shifts throughout the day, AESO system controllers use the merit order to dispatch power to the Alberta Interconnected Electric System (the transmission grid, or AIES) and to balance supply and demand. As demand increases, the controllers move up the merit order, dispatching the next eligible supply or accepting the next demand bid. As system demand declines, the controllers dispatch down the merit order, instructing suppliers to reduce output or instructing consumers to increase demand. The lowest-priced power is dispatched first, followed by the next lowest and the next lowest, until all the electricity supply required to meet demand has been dispatched.

Figure 1: The Pool


Source: An Introduction to Alberta’s Financial Electricity Market,
Market Surveillance Administrator (9 April 2010).

The last eligible electricity block dispatched to meet demand sets the system marginal price for electricity (SMP). Accordingly, the SMP is set “at the margin” where supply and demand intersect, and is also referred to as the “market clearing price”. The SMP is set on a minute-to-minute basis, and at the end of every hour the time-weighted average of the 60 one-minute SMPs is calculated and published as the pool price for that hour. Wholesale electricity is financially settled at this real-time, hourly pool price. Average pool prices in Alberta for the last six years were:

Year

Avg. Pool Price

2010

$50.88

2011

$76.22

2012

$64.32

2013

$80.19

2014

$49.42

2015

$33.34

Source: 2015 Annual Market Statistics, AESO;
Electricity Statistics, Alberta Energy.

The hourly pool price is posted by the AESO at the end of each delivery hour. Thus, the SMP and the pool price reflect the economic dispatch of the merit order and reflect the prevailing electricity market economics. The pool price serves as an index to settle electricity transactions that occurred in the pool and is the logical candidate for use as the reference price for settling financial contracts for power in Alberta.

C. Contracts for Differences

What are CFDs?

A CFD is a bilateral financial agreement whereby differences in valuation are paid in cash and without the delivery of goods, commodities or securities, often with reference to a spot price. For power, CFDs may be used with reference to an appropriate electricity market price. As such, a CFD is not a contract of purchase and sale for physically delivered power between a generator and a user (better known as a power purchase agreement). Where the market price varies from settlement interval to settlement interval within a single day, CFDs offer parties the ability to hedge against spot price volatility by agreeing to a specific volume and price (the contract price). In the case of Alberta’s wholesale market, the pool price and an amount of power delivered by a generator to the AIES could be the basis of such an exchange of value between parties.

Under a CFD, the usual arrangement is that one party fixes its price while the other party takes the risk of commodity price fluctuations. In the Alberta context, if a generator wished to fix its price it would want to settle the CFD on the basis that when the pool price is lower than the contract price, the counterparty would pay the difference to the generator. However, if the pool price exceeded the contract price, the generator would pay the difference to the counterparty. In this way, the generator would receive a fixed price for the power it generates, and the counterparty would obtain the upside of market prices that exceed such fixed price and thereby would take market risk. CFDs are typically settled monthly by a payment from one party to the other. The monthly payment is determined using a “sum of” calculation, totalling and netting the difference payments for all of the settlement intervals in the month.

Figure 2: CFD Settlement

Depending on the commercial objectives of the parties to the transaction, the difference payments may be calculated based on the volume of power actually delivered by the generator in that settlement interval or a generation profile that is a portion of such delivered power. The monthly payment may be subject to adjustment if the transaction contemplates parameters regarding quantities or timing of delivered power (e.g. a lower contract price for power delivered in excess of a predetermined quantity or a higher contract price for power delivered in peak periods). Again, the counterparty is not actually taking delivery of such power, but depending on such parameters the generator may be motivated to generate and deliver power to the grid in ways that are intended to meet specific power system objectives.

In the context of renewable generation procurement, long-term CFDs have been often designed to have a counterparty top up the generator to a contract price for all of the energy it is able to supply to the grid. The top up of the revenue that the generator has earned in the market is illustrated in the previous diagram. Also illustrated is the repayment by the generator of its market revenues in excess of contract prices. This arrangement allows predictable cash flows to the generator despite spot price volatility, and motivates the generator to run at full capacity if and when available. It also allows generators to concern themselves only with wind and other operating risks, removing price risk from the equation while providing some assurance of recovery of capital costs and ability to service debt over the long-term.

D. Implementation in Alberta

Key Issues

With the Alberta government having made the policy decision to procure significant renewable energy capacity, if CFDs are ultimately chosen as the mechanism to stimulate renewable generation construction there are several important contractual issues that would need to be addressed. Key to these issues is addressing them in a manner that meets the government’s objectives while allocating risk between private investors and the Province based on which party is more reasonably able to absorb such risks. The impetus to allocating risk to the party that is best able to mitigate such risk is efficiency. If the government is seeking the best pricing in a competitive procurement, it undermines its objectives to have respondents pricing-in the costs of mitigating risks that they cannot reasonably or efficiently handle.

As a starting point, the significant issues include:

  • the contract price and price adjustments;
  • the identity and creditworthiness of the counterparty;
  • issues related to curtailment and dispatch control;
  • the definition and application of force majeure;
  • change of law; and
  • sovereign risk.

Determining Contract Price

Determining the contract price will be critical, both in setting the initial price and in adjusting for inflation over the term of the contract. As has been seen in most Canadian jurisdictions that have made serious efforts to procure green energy, renewable generation projects have competed for contracts with at least a twenty year term tailored to allow for recovery of capital costs and a return on equity. Such periods match expected equipment life and system planning goals with a reasonable cash flow disbursement period for the counterparty that does not create immediate system shock as the result of the implementation of funding or payment recovery measures. Annual adjustments are intended to mitigate the risk to generators of reasonably anticipated escalation in operating and maintenance costs in order that expected returns are not eroded over the course of a long-term contract due to normal economic movements. In contrast, capital and borrowing costs are notionally fixed for the term of the contract and are the generators’ risk. A key determination will be what percentage of the contract price is notionally intended to compensate generators for future operating and maintenance costs and should therefore be subject to annual adjustment. Another key determination will be what drivers will affect operating and maintenance costs over time and what appropriate adjustment indices will be required to mitigate extraordinary risks without providing windfalls to generators.

Counterparty Risk

Whether renewable electricity generators are taking on counterparty or default risk is dependent on the creditworthiness of the CFD counterparty. Realistically, while generators or their equity sponsors may have a greater tolerance for such risk, if they are seeking senior secured debt their projects will not be financeable without a creditworthy counterparty. The Canadian power procurement experience to date has been that the risk of providing a credible counterparty has belonged to the procurement party and is generally covered by an incumbent provincial power utility or government procurement agency with credit ratings of “A” or higher. In our view, a similarly creditworthy counterparty will be necessary and appropriate in Alberta.

From a counterparty risk perspective, the ideal solution for renewable generators in Alberta would be for the provincial government to designate an entity as the counterparty that is an agent of the Crown, such that the full faith and credit of the province stands behind the CFDs. If the designated counterparty is not an agent of the Crown, it will require an acceptable credit rating that may be derived from its statutory or regulatory powers or some other financial wherewithal.

While the government of Alberta could establish an entirely new entity as CFD counterparty, there are a few existing Alberta entities that are potential candidates to act as the CFD counterparty. Alberta’s Balancing Pool is one. The Balancing Pool is a corporation that was established in 1999 under the Electric Utilities Act to facilitate the transition of Alberta from a cost-of-service model to a deregulated electricity market model. While the Balancing Pool’s responsibilities include, among others, backstopping the Alberta heritage power purchase arrangements (PPAs),[4] the Balancing Pool is not an agent of the Crown. The Balancing Pool has the ability to recover its budget through the AESO Tariff, so that any surplus or deficit it runs can be allocated to Alberta’s power consumers through a customer payment or surcharge.[5] If the Province wished to designate the Balancing Pool as the CFD counterparty it would need to alter the organization’s mandate to expressly allow it to recover payments it makes under such CFDs. While the Balancing Pool does not currently have a credit rating, the ability to recover CFD program revenue from customer surcharges could result in it earning a province-like credit rating.

Alternatively, the Province could designate the Climate Change and Emissions Management Corporation (CCEMC) as the CFD counterparty. The CCEMC is a corporation established in 2009 as part of the Province’s climate change management strategy. Like the Balancing Pool it is not a Crown agent. The CCEMC is currently responsible for distributing payments from the Climate Change Emissions Management Fund, which is funded by payments made pursuant to the Specified Gas Emitters Regulation. The CCEMC would be well-suited for the administration of a CFD program, potentially through funding obtained under the carbon tax introduced in the Climate Leadership Implementation Act and taking effect on January 1, 2017.According to the legislation, the revenue from the carbon tax may only be used for “initiatives related to reducing emissions of greenhouse gases or supporting Alberta’s ability to adapt to climate change”, or to provide rebates and adjustments in respect of the carbon tax, thus making it a potential source of funding for a CFD program. This is consistent with Alberta’s 2016 Budget, which estimates $9.6 billion in gross revenue will be raised from large industrial emitters and the carbon levy (i.e. under the Specified Gas Emitters Regulation and Bill 20), and states that one of the priority areas for investment of that revenue is renewable energy.[6] Although not an agent of the crown, the CCEMC’s sources of funding under the Specified Gas Emitters Regulation and the Climate Leadership Implementation Act may provide sufficient assurances for province-like credit worthiness.

Regardless as to which credible and creditworthy counterparty is put forward as a CFD counterparty, reasonable assignment and change of control restrictions will also be necessary to ensure that the confidence that investors and project lenders have in such counterparty will be retained for the entire term of the CFD.

Compensation for Curtailment

Terms surrounding the ability of the counterparty to curtail power delivery and the compensation, if any, for such curtailment will be crucial in assessing the viability of the CFDs. It is appropriate for generators to take operational risk and part of this is grid risk in the normal course. For example, forced outages on transmission grids caused by lightning or other events that a generator cannot reasonably avoid should afford force majeure protection to generators. Under such circumstances a generator should, at a minimum, be relieved of its performance obligations. On the other hand, the possibility of curtailment risk due to transmission system congestion is a significant possibility in the Alberta market.

In our view, the robustness and adequacy of grid infrastructure as a whole is more appropriately a risk socialized among all electricity ratepayers and, indeed, is the basis for the compensation of transmitters and distributors in Alberta. Renewable generators will be less willing to take on such endemic system risks without compensation for lost generation in addition to force majeure protection. Such risk is particularly significant for wind generation in Alberta due to the location of wind resources in the province and the state of the AIES in that area. Alberta’s best wind resources are found in the southwestern part of the province in the Pincher Creek area, located in the AESO’s South Planning Region.[7] In this region, the AESO has identified the need for significant transmission system reinforcements in order to serve generation sources in the area, and has implemented the Southern Alberta Transmission Reinforcement (SATR) project to address it. The SATR project is in varying stages of development, and certain transmission lines that the AESO identified as necessary to alleviate congestion and to accommodate new wind generation sources have faced significant public opposition and a lengthy regulatory process (again, risks more appropriately socialized in the context of meeting public objectives). A number of wind generation projects are currently in stasis in the AESO’s connection queue process due to the lack of ability to connect to the AlES without imposition of a remedial action scheme.

Similarly, in our view it is also the case that private generators should not be required to take the risk of the provincial economy as a whole or changes in system planning arising from government policy. Such risk may be embodied as “economic curtailment” where provincial power capacity exceeds provincial demand, leading to the curtailment of newly procured generators who are otherwise ready and willing to operate. As an example, based on the provincial government’s stated objectives, new renewable generators expect that approximately 6,267 MW of thermal generation capacity[8] will be removed from service by 2030. If there is a change in planning such that this capacity remains operational and load has not kept pace with increased installed capacity, new generators will want to be compensated for electricity that they reasonably expected to be able to produce based on a supply forecast that they reasonably relied upon. Thus, the attractiveness of CFDs in the Alberta market will depend at least in part on the Province’s willingness to compensate for curtailment caused by transmission system congestion as well as economic curtailment, and also on the Province’s ability to undertake the transmission system upgrades required to connect renewable generation to the AIES without requiring remedial action schemes.

Force Majeure

The definition of what events constitute force majeure under the CFDs should be carefully considered. The negotiation of the terms of force majeure provisions is complex and transaction-specific but it is also necessary in order to allocate the risks of events that are beyond the generator’s control. For instance, during the period of development and construction of a project, a generator should be able to claim force majeure with respect to unusual delays caused by difficulty in obtaining necessary government permits and approvals under the CFD on the basis that the timely issuance of such permits is within the control of government-funded and resourced agencies. In order to allow generators relief from such unusual delays, in our view force majeure provisions in the CFDs must expressly include such delays.

Change of Laws

Who should bear the risk of changes in laws: the person who makes the laws or the person who must comply with them? Sometimes it depends on the laws and the changes. Electricity industry participants expect that their operations will be subject to regulation, and that the statutes, regulations, codes and rules that create such regulatory framework will be refined over time. Accordingly, normal course “evolutionary” changes in regulation are generally accepted as operational risk. Also, it is generally accepted in Canada that there is political and functional separation between regulatory bodies and government with the intention that regulators may perform their duties without political interference. However, concerns that political imperatives could influence regulatory oversight or enforcement are not imprudent. On the other end of the spectrum of legal compliance, it is possible to have changes in statutes that are directed at, or have the effect of, materially changing the economics of investments previously procured by government. For such sweeping changes it is reasonable to conclude that because they are within the control of government the risk of such “revolutionary” changes are more efficiently borne by the public.

Change of laws clauses are often contained in government-sponsored procurement contracts to deal to some degree with the foregoing risks. In our view, effective clauses broadly define “laws” and the consequences of changes to such laws on generators, and provide clear and time-limited processes for renegotiation to mitigate such consequences. They also provide for dispute resolution and remedies if such negotiations are not fruitful. Such clauses would be appropriate and necessary for inclusion in the CFDs. Whether the government agrees or not, the reality is that the highly-publicized recent litigation[9] commenced by the Alberta government seeking, among other things, a declaration to void amendments made to the “Change of Law” provisions within certain twenty-three year old power purchase agreements[10] will put this issue front and center in any renewable generation incentive program that it introduces.

Sovereign Risk

Closely related to the risk of changes of law are investors’ concerns about sovereign risk. In Canada, it is well-established that government has the power to pass laws that limit a private party’s rights, including rights that such party may have just previously obtained in a contract with such government or its agency. Put more bluntly, when politicians or activists advocate ripping-up or terminating “outrageous” contracts, this is the spectre of “sovereign risk”. It is a real concern for domestic and foreign investors even in Canadian provinces where more than lip-service is paid to ideals of sanctity of contract and rule of law and the benefits of in-bound investment are understood.

In our view, it is reasonable to include in the CFDs robust contractual provisions to provide assurances through strong remedies that government will not engage in arbitrary or discriminatory actions. We acknowledge, however, that such provisions may be of little worth for the reasons just noted. Accordingly, some gratuitous advice to government may be more appropriate. First, reputation is important. Capital is mobile and jurisdictions compete for it. Canadian provinces are attractive destinations for domestic and foreign investment because of our respect for the rule of law and the agreements we enter into. However, with all other investment criteria being equal, Alberta could lose the interest of investors if its form of renewable generation incentives do not appear “market” compared to those of other jurisdictions. Alternatively, the Province’s procurement could lose efficiency as less risk-averse investors agree to participate but price-in sovereign risk premiums.

Second, what makes political sense does not always translate into economic sense. In the past, both federal and provincial governments have terminated contracts and it has rarely been the case that government has come out unscathed. For example, the Ontario government discovered that power contract termination can result in unintended expenditures of both financial and political capital. Last, and this suggestion is directed toward industry as well as government, the best mitigant for sovereign risk is to negotiate a reasonable deal up-front that meets the objectives of both parties. Both government and industry must recognize that no matter what the terms of such deals may be, it is inevitable that there will be critics. Government needs to maintain the courage of its convictions to enter into and defend its arrangements with private investors. Likewise, generators must enter into reasonable transactions that are defensible by government sponsors, as economic reasonableness is an accepted pillar of social licence.

E. Next Steps?

As the AESO’s deadline for launching the REP fast approaches and specific information regarding Alberta’s renewable program remains scarce, briefing statements suggest that the Province is committed to maintaining the energy-only market and will not be issuing power purchase agreements for renewable capacity (as opposed to renewable energy).

The mechanism by which Alberta intends to attract renewable generation is a critical input for investment decisions and project modelling. A CFD model provides an attractive mechanism, as it provides financial certainty for both generators and government and can efficiently and appropriately allocate risks between them to ensure the most favourable cost outcomes. We note that the same considerations discussed in this article are equally applicable to alternative mechanisms for attracting renewable generation investments, be they the creation of renewable energy credits or physical power purchase agreements. We will be watching these developments closely. Timely updates on Alberta’s announcements and chosen path can be found on Canadian Energy Perspectives, McCarthy Tétrault’s blog on developments in Energy and Power Law.

Seán O’Neill is a partner in our Power Group in Toronto and has negotiated power purchase and derivative agreements representing over 2,500 TWh of electrical energy, including a 49-year contract for differences for 6,300 megawatts of nuclear generation capacity.

Michael Weizman is a partner in our Power Group in Toronto and practises primarily in the energy area. He has participated in all aspects of the development of power projects, including the negotiation of power purchase agreements and other material project agreements.

Kimberly Howard is a senior associate in our National Environmental and Regulatory Group and Power Group in Calgary and acts for clients in regulatory and permitting matters and negotiating power purchase agreements for wind generation projects in Alberta.

Kim Macnab is an associate in our National Environmental, Regulatory and Aboriginal Group and Power Group in Calgary and acts for clients in regulatory and permitting matters for wind generation projects in Alberta.



[1] Kimberly Howard, Selina Lee-Andersen & Gordon Nettleton, “At Last: Alberta Unveils its New Climate Leadership Plan”, Canadian Energy Perspectives, online: http://www.canadianenergylawblog.com/2015/11/23/at-last-alberta-unveils-its-new-climate-leadership-plan/.

[2] Climate Leadership Plan: Ending Coal Pollution, online: http://www.alberta.ca/climate-coal-electricity.aspx.

[3] Kimberly Howard & Kimberly Macnab, “The AESO’s Renewable Electricity Incentive Program Marches Forward”, Canadian Energy Perspectives, online: http://www.canadianenergylawblog.com/2016/05/10/the-aesos-renewable-electricity-incentive-program-marches-forward/.

[4] For a description of such PPAs and this issue see our blog: Kimberly Howard, Kimberly Macnab and Seán O’Neill, “Alberta Power Market Update”, Canadian Energy Perspectives, online: http://www.canadianenergylawblog.com/2016/10/18/alberta-power-market-update/.

[5] EUA, s 82.

[6] Fiscal Plan 2016-19, Government of Alberta, online: http://finance.alberta.ca/publications/budget/budget2016/fiscal-plan-complete.pdf, p 6.

[7] AESO 2015 Long-term Transmission Plan.

[8] Alberta’s installed generation capacity for coal-fired generation facilities as of June 2016 is approximately 6,267 MW, representing approximately 39% of Alberta’s total installed generation capacity: “Electricity Statistics”, Alberta Energy, online: http://www.energy.alberta.ca/electricity/682.asp.

[9] Originating Notice of Application filed at the Alberta Court of Queen’s Bench on July 25, 2016 (ABQB Action No. 1603-13041), online: http://www.alberta.ca/documents/PPA-Originating-Application-2016-07-25.PDF.

[10] See e.g. Nigel Bankes, “The Termination of Power Purchase Arrangements in Alberta: What is the Legal Position and What are the Implications of the Termination”, ABlawg (24 March 2016), online: http://ablawg.ca/2016/03/24/the-termination-of-power-purchase-arrangements-in-alberta-what-is-the-legal-position-and-what-are-the-implications-of-termination/.