Nearly two decades after Ontario deregulated “hydro” and introduced a competitive wholesale electricity market, Ontario’s electricity industry continues to grapple with how to efficiently and reliably ensure resource adequacy for electricity consumers.¹ Indeed, the costs associated with Ontario’s electricity system have been repeatedly scrutinized, and the Independent Electricity System Operator (IESO) continues to consult the industry on implementing additional resource adequacy mechanisms, mainly capacity auctions and competitive procurement by Requests for Proposals (RFP).² Currently, Ontario relies on the combination of rate-regulated heritage resources, a wholesale spot market, and government-backed contracts to meet provincial resource adequacy requirements, which are set by the North American Electric Reliability Corporation (NERC). This paper posits that Ontario’s resource adequacy framework would benefit from enabling a robust bilateral contracting market where demand-side participants, specifically loads and retailing entities, contract for their own electricity supply needs.³ For clarity, bilateral contracts are contracts entered into for the purchase and sale of electricity or electricity-related products, typically between a generator as one party and an offtaker (i.e., purchaser of a production facility’s output) as the counterparty.⁴ A robust bilateral market is an efficacious and cost-effective resource adequacy mechanism because first, it enables demand-side participants (i.e., loads and retailing entities) to add to system capacity by acting as offtakers providing secure revenues for the development of new resources. And second, demand-side participants can provide additional revenue streams for existing resources that are economically managed, enabling them to stay in operation longer and deferring the need for the construction of new resources, which is generally more costly. As a result, enabling a robust bilateral market should be considered as an additional resource adequacy mechanism for Ontario in the IESO’s Resource Adequacy consultation, and one that is complementary to existing and planned resource adequacy mechanisms in Ontario. This paper proceeds by first elaborating on how a robust bilateral contracting market is an effective resource adequacy mechanism because it supports the development of new resources when needed and defers the need for new resources if there are existing cost-effective resources available, followed by an examination of Ontario’s bilateral market under the existing resource adequacy framework where the IESO is the only viable contractual counterparty in Ontario, and finally presenting how a robust bilateral market can work in Ontario by addressing obstacles arising out of Ontario’s system cost allocation and industry structure.

BILATERAL CONTRACTING SUPPORTS THE DEVELOPMENT OF NEW RESOURCES AND EXTENDED OPERATION OF COST-EFFECTIVE EXISTING RESOURCES

A robust bilateral contracting market as envisioned in this paper entails increased activity for the purchase and sale of electricity or related products transacted through bilateral contracts between generators and loads or retailing entities as counterparties. These contracts typically contain legal terms addressing duration of contract, price of performance, times of performance, delivery location, and other terms which may be applicable to the transaction.⁵ For example, it is typical for Power Purchase Agreements (PPAs), a common type of bilateral contract, to contain a contractual term spanning 10–25 years. As the development of new generation resources often require stable, multi-year revenues to obtain project financing, bilateral contracts are an effective tool for supporting new resources. Indeed, in its report to the American Public Power Association on the role of bilateral contracting in deregulated U.S. electricity markets, Synapse Energy Economics found that the development of new resources has been supported on the basis of long-term contracts.⁶ For example, Load Serving Entities (LSEs) in the U.S. enter into bilateral contracts with generators as part of integrated system planning to secure capacity for their mandated standard supply obligations. Further, loads and competitive retailers use bilateral contracts to hedge against spot price volatility by securing a long-term fixed energy price directly from a generator; this activity is especially prevalent in jurisdictions with energy-only markets such as Alberta and Texas, where spot price volatility is high.

Collectively, this type of transactional activity is referred to as a bilateral market, and unless a transaction is subject to a regulatory proceeding (e.g., part of integrated system planning or designing a standard offer program), the terms are often kept confidential between the parties to the contract. Moreover, bilateral contracts are increasingly being used by companies and utilities to secure bundled renewable energy in support of corporate sustainability and policy (e.g., renewable portfolio standards) objectives, respectively. In fact, from 2016–2019 it is approximated that the development of an additional 20 GW of renewable energy capacity has been supported by corporate offtakers in the U.S.⁷ Many of these contracts contain terms spanning 8–12 years, which have proven viable for obtaining financing and supporting the development of new resources.

Without long-term contracts or regulated rates, developers depend on merchant opportunity, characterized by sufficiently high spot market revenues, or capacity payments to recover capital costs for new resources. While the IESO plans to implement a capacity auction (CA) starting December 2020, the current design only contemplates a 1-year commitment period, as opposed to the multi-year revenues often required for new resources.⁸ Further, since deregulation Ontario has been using long-term government-backed contracts to de-risk the development of new resources through fixed-price or out-of-market settlements to support cost recovery, which along with over-procurement of supply resources has contributed to diminishing merchant opportunities.⁹

Furthermore, existing resources require periodic capital investment throughout their lifetime to maintain reliable operation. This means that in the absence of sufficient merchant opportunity, existing resources also require additional revenue streams to recover the costs of incremental investment required to maintain operation, otherwise be “mothballed” (i.e., cease operations and take their capacity off the system) if not profitable. This way a robust bilateral market provides additional liquidity for generators to acquire necessary revenue streams following the expiration of any initial contracts. By extending the operation of existing resources that are economically managed, a robust bilateral market can defer the need for the construction of new resources, which is generally more costly and carries with it the additional risk of becoming stranded.

While capacity markets were introduced in several deregulated U.S. jurisdictions specifically to address this issue by providing additional revenue through capacity payments, a robust bilateral market offers at least two advantages.¹⁰ First, freely negotiated bilateral contracts allow for better price discovery, as the purchaser is able to indicate its willingness to pay as opposed to a capacity auction, which uses a demand curve based on a target reserve margin and a reference price, where the reference price is a proxy for the cost of new entry of a reference resource (e.g., simple cycle gas turbine is most common). Second, there is long-standing criticism that capacity markets over-procure resources and lead to overall cost increases. To illustrate this point consider evidence put forward during the Alberta Utilities Commission’s capacity market proceeding (23757).¹¹ In analyzing the Alberta Electric System Operator’s (AESO) proposed demand curve parameters, ENMAX, supported by the Market Surveillance Administrator (MSA), found that the capacity market would clear an excess of 127–443 MW of capacity resulting in $401 million to $1.134 billion per year more capacity cost to Alberta.¹²

The following section will discuss the current condition of Ontario’s bilateral market.

ONTARIO’S BILATERAL MARKET UNDER THE EXISTING FRAMEWORK AND THE IESO AS THE ONLY VIABLE COUNTERPARTY

Under the current statutory framework, The Minister of Energy (currently, Minister of Energy, Northern Development and Mines (MENDM)) and the IESO are responsible for system planning.¹³ The IESO administers a competitive wholesale market and assists the MENDM in preparing a Long-Term Energy Plan (LTEP) by publishing planning documents such as outlooks and forecasts, and identifying system needs. Meanwhile, the MENDM is statutorily required to publish LTEPs every 3 years, although a proposed amendment has been issued to revoke the timing requirement.¹⁴ It also possesses the authority to direct the IESO (by issuing Ministerial Directives) to engage in competitive procurement initiatives or directly enter into contracts with generators or electricity service providers. The latter mandate was adopted by the IESO as it was merged by statutory amendment with the Ontario Power Authority (OPA) in 2015, retaining the IESO name.

Since its inception in 2005 the OPA under Ministerial Directives has engaged in numerous competitive procurement initiatives and entered into contracts (most of which contain a 20-year term) with generators either directly or through standard offer programs. According to the IESO’s Contracted Electricity Supply Progress Report, the IESO held 26,750 MW of contracted capacity at the closing of June 2020.¹⁵ Although this makes up more than half of Ontario’s 2019 installed capacity of 40,500 MW, it does not include Ontario Power Generation’s (OPG) rate-regulated assets (but does include its natural-gas fired facilities), heritage assets, and Non-Utility Generation (NUG) contracts held by the Ontario Energy Finance Corporation.¹⁶ The fuel supply mix of generation contracted with the IESO is comprised mainly of natural gas (9,450 MW), nuclear (6,300 MW), wind (5,333 MW), solar (2,673 MW), hydropower (2,410), with smaller amounts of bioenergy and waste (see Figure 1).

Figure 1: Contracted capacity in Ontario by fuel type¹⁷

A closer examination of the performance and compensation provisions contained in the IESO/OPA contracts demonstrates how they provided full cost recovery to generators.¹⁸ For example, Clean Energy Supply (CES) contracts were designed to provide “capacity style” payments to natural gas-fired generation facilities on a $/MW-month basis during which the generator must offer its energy into the spot market.¹⁹ The determination of the sum was based on a Net Revenue Requirement (NRR) provided in the proponent’s economic bid statement and valuation of revenues and costs.²⁰ Effectively, the CES contract payments functioned such that if the generator operated according to its contractual profile (i.e., deemed dispatch), then it would earn its required level of cost recovery and profit. Further, consider the example of Feed-in-Tariff (FIT) contracts, which were designed to compensate renewable resources (mainly, solar, wind, biomass, and hydroelectric) based on a $/MWh of energy supplied to the grid. Since these are variable output generation resources, the contract was designed such that the generator first settles through the spot market as a price-taker, and subsequently the IESO would provide additional payments to the generator based on the difference between the market-settled revenue and a guaranteed revenue amount prescribed by the contract.

In fact, the primary objective for the creation of the OPA under the Electricity Restructuring Act, 2004 was to create a centralized planning and procurement agency that can enter into contracts as a financial counterparty. To cover the costs arising out of contract payments made to generators, the Electricity Restructuring Act, 2004 additionally created the Global Adjustment (GA) charge, which is levied against all electricity consumers.²¹ However, providing contractually guaranteed, out-of-market payments to generators contributed to a negative feedback loop that diminished merchant opportunity for generators, diminished the value of bilateral contracting for loads and retailing entities, and de facto established the IESO as the only viable counterparty in Ontario.

Specifically, out-of-market payments enabled a significant number of price-setting generators to offer their energy into the wholesale market potentially below the marginal cost of production. This, coupled with a substantial uptake of near-zero marginal cost wind and solar resources during flatlining demand consequently contributed to lowering the average Hourly Ontario Energy Price (HOEP) (i.e., spot price) and leading to diminished merchant opportunity. Subsequently, given the inverse relationship between GA and HOEP due to the design for resource compensation contained in the IESO contracts and increased contracting by the IESO pursuant to Ministerial Directives, the proportion of GA in relation to HOEP has grown substantially. For example, in 2019 GA comprised approximately 80–85 per cent of the wholesale energy cost (see Figure 2).²² Since the GA portion is largely fixed and under Ontario Regulation 429/04²³ and the GA charge cannot be avoided through a retail transaction, there is little value to be gained by loads by entering into a bilateral contract to only hedge against the HOEP. This also effectively diminishes the business case for engaging in competitive electricity retailing in Ontario.²⁴

Figure 2: Average HOEP Plus GA²⁵

As mentioned, the negative feedback loop described above continues to reinforce the IESO as the only viable counterparty in Ontario. This is further complicated by a feature of Ontario’s industry structure, where Local Distribution Companies (LDCs), despite having a standard supply obligation under the Ontario Energy Board’s (OEB) Standard Supply Service Code, do not have an obligation to secure resource adequacy or hedge energy prices for their customers in contrast to LSEs in the U.S. and thus, among other reasons, do not contract for generation.

The following section will discuss how a robust bilateral market can be enabled in Ontario by addressing the obstacles to contracting by demand-side entities.

ENABLING A ROBUST BILATERAL MARKET IN ONTARIO TO SUPPORT INCREASED DEMAND-SIDE CONTRACTING

Despite the IESO’s decision to include the continued use of government-backed contracts in the Resource Adequacy framework, further entering into additional contracts for future resource adequacy needs could prove difficult for the IESO given the high amount of fixed costs in the GA.²⁶ Indeed, this reason was likely a significant driver behind the interest for implementing a capacity market in Ontario ever since the Market Renewal Program (MRP) was announced in 2016.²⁷ That said, according to the latest Planning Outlook, the IESO does not anticipate a capacity need to occur until the mid-2020s at least (notwithstanding the forecast impacts of the COVID-19 pandemic), largely attributed to supply factors such as nuclear units coming offline for refurbishment and expiring contracts (see Figure 3).²⁸ This presents an opportune time to consider enabling a robust bilateral market in Ontario to be used alongside the existing and planned resource adequacy mechanisms.

Figure 3: Installed Capacity by Commitment Type 2020–2040²⁹

In order to enable a robust bilateral market in Ontario, the obstacles that currently hinder demand-side participants from engaging in bilateral contracting must be addressed. As discussed above, the main obstacles are system cost allocation (i.e., the GA charge) and the role of electricity distributors (i.e., LDCs) in Ontario. While this paper does not purport to offer original solutions to these obstacles, it does refer to two options that have been separately proposed for Ontario as a springboard for further discussion. The first option, presented by Brian Rivard at the Ivey Energy Policy and Management Centre involves breaking up the GA into three separate components (i.e., capacity costs, an OPG energy price hedge, and system-wide fixed costs) and applying a different cost recovery method to each component (see Figure 4).³⁰ The second option, presented by the Ontario Energy Association (OEA) involves creating a regulatory model for LSEs in Ontario that would enable LDCs to voluntary take on the role of LSEs and engage in resource adequacy and contracting activities.³¹ As will be elaborated below, the first option is aimed at addressing the challenges associated with the GA charge and the second option is aimed at addressing the challenges associated with Ontario’s industry structure, where LDCs as electricity distributors do not engage in bilateral contracting.

Figure 4: Monthly Global Adjustment by Component (March 2019 – March 2020)³²

Rivard argues that the GA can be seen as being comprised of three different categories and sources of system costs. The first category is generation capacity costs, which are the costs incurred to secure and maintain resources. Given that the need for additional resources is driven by metered customers who consume electricity from the grid during peak times, it is recommended that this portion be recovered through a proportional demand charge to consumers who drive the need for additional resources. The second category is the OPG energy price hedge, which was created in order to share revenues earned by and above OPG’s heritage assets’ revenue requirements, but given the high resource costs and declining HOEP (i.e., wholesale energy price) turned from a rebate to a cost. It is recommended that this be recovered volumetrically from all consumers. The third category is system-wide fixed costs, which involve costs incurred in connection with governmental social or environmental policy objectives. It is recommended that this be recovered through a mix of fixed and volumetric charges or be removed from the GA altogether and shifted into the tax base.

Meanwhile, the OEA’s Recommendations for an Ontario LSE Model paper posits that Ontario can benefit from the creation of a regulatory model for LSEs to provide LDCs with the option to voluntarily transition and become LSEs, defined by the obligation to secure incremental resource capacity for their respective distribution service territories. In practice, voluntary LSEs would be responsible for creating Integrated Resource Plans (IRPs) beyond their usual Distribution System Plans (DSPs) that would consider incremental supply resources. Another important element is the necessary coordination that would need to occur between LSEs and the IESO. Specifically, IRPs created by the LSEs would need to be considered as inputs for Capacity Auctions or competitive procurements (e.g., RFPs), where any LSE procurement would need to be accounted and adjusted for in the capacity target for the appropriate capacity zone.

Rivard’s GA allocation proposal presents a window into how barriers arising out of system cost allocation can be addressed to promote bilateral contracting by loads. For example, consider a solution where loads can enter into bilateral contracts in coordination with the IESO, and if the resource contributes to system capacity, the load should be allowed to reduce a portion of its GA costs on the basis of one of the components identified by Rivard. While on one hand, this may seem as an inequitable cost-shifting mechanism rather than cost-reducing mechanism, on the other hand, the addition of the load’s contracted resource may lead to the deferral or avoidance of otherwise needed system investment costs. This example is presented for illustrative purposes and requires a closer analysis to determine the trade-off between cost and benefit of implementing such a program. Similarly, the LSE paper presents a much more direct solution to the challenges associated with the role of LDCs in Ontario’s industry structure. By adopting a resource adequacy obligation, LDCs as LSEs will be required to become active demand-side participants in the bilateral market to secure incremental resources. Given that Ontario’s system cost allocation electricity industry structure is governed by legislation, addressing these obstacles may require legislative amendments or amendments to other regulatory instruments (e.g., OEB Codes and Licenses). Both of these Demand-side entities can design contracts that offer payments in concert with wholesale market revenues similar to the IESO contracts and thus make bilateral contracting work in Ontario without further inflating the GA. For example, virtual PPAs (also known as financial PPAs or contract-for-differences) are based on an agreed upon strike price that is settled between two parties in relation to the spot price.

Finally, as stated, a robust bilateral market can work alongside Ontario’s other existing and planned resource adequacy mechanisms, which are the IESO-administered markets, including the planned capacity auctions, competitive procurements (e.g., RFPs), and the Government’s ability to direct the IESO to solicit a competitive procurement or directly enter into agreements for identified system needs. With respect to market mechanisms, a robust bilateral market can function alongside a capacity market as is the case in northeast U.S. deregulated markets such as PJM, NYISO, and ISO-NE.³³ Although, in those jurisdictions capacity markets remain the primary resource adequacy mechanisms with bilateral contracts used mainly for hedging against future price risk and to support the development of renewable resources to meet procurement policy objectives (e.g., Renewable Portfolio Standard). This enables generators to stagger and hedge their capacity by offering a portion into the capacity market for a shorter-term obligation and contracting out a portion for a longer-term commitment. Similarly, a more robust bilateral market would not interfere with the IESO’s ability to enter into contracts if a need arises that requires a more centralized solution.³⁴

CONCLUSION

This paper presented the position that Ontario’s resource adequacy framework would benefit from enabling a robust bilateral market, characterized by increased contracting activity from demand-side participants, specifically loads and retailing entities. This in contrast to the current model where the IESO is de facto the only viable contractual counterparty in the province. With a robust bilateral market, demand-side participants could enter into agreements with new resources or existing resources that are economically managed, thereby contributing to system capacity by bringing new generation projects online or deferring the need for them if existing resources are more cost-effective. A robust bilateral market could also bring additional benefits such as innovative energy solutions using emerging technologies (e.g., generation paired with storage) and increased buy-side competition. To enable a robust bilateral market, the obstacles that currently hamper the ability of demand-side participants would need to be addressed. Specifically, two potential areas of exploration are system cost allocation and industry structure related to the role of LDCs in Ontario. That said, a fundamental restructuring such as that which ensued by deregulation is likely not necessary as a robust bilateral market can function properly alongside the current (i.e., energy market, Directive powers and IESO contracting ability) and planned (i.e., capacity market and RFPs) resources adequacy mechanisms used in the province. Thus, enabling a bilateral market should be considered in the IESO’s Resource Adequacy Engagement as it can help efficiently and reliably manage electricity supply for Ontario consumers.

*Nathan is a Consultant at Power Advisory LLC, where he focuses on providing support in areas of electricity markets, regulation, and policy. He holds a law degree from Osgoode Hall Law School and a Master’s degree in Environmental Studies from York University.

1. Resource adequacy is the ability of the electric grid to reliably produce and deliver electricity to Ontario’s consumers (e.g., residential, commercial & industrial, government, etc.). Deregulation refers to the implementation of the Energy Competition Act, 1998, SO 1998, c 15 as it appeared on 30 October 1998, which restructured Ontario’s electricity supply chain by breaking up the vertically integrated Ontario Hydro and creating an independent system operator to administer a spot market.
2. IESO, “Resource Adequacy Engagement” (28 September 2020), online (pdf): <www.ieso.ca/-/media/Files/IESO/Document-Library/engage/rae/ra-20200928-presentation.pdf?la=en>.
3. Loads refers to commercial, industrial, institutional (i.e., large) electricity consumers. Retailing entities refers to both electricity distributors with standard supply obligations and commercial retailers.
4. An electricity-related product may be electric energy, capacity (including demand response), ancillary services such as reserves and frequency regulation, or some combination of those (See Ezra Hausman, Rick Hornby & Allison Smith, “Bilateral Contracting in Deregulated Electricity Markets: A Report to the American Public Power Association” (18 April 2008), online (pdf): Synapse Energy Economics <citeseerx.ist.psu.edu/viewdoc/download?doi=10.1.1.179.1344&rep=rep1&type=pdf>; In addition to the physical products described, bilateral contracts can be used for financial hedging as forward contracts).
5. Hausman, supra note 4.
6. Ibid at 11.
7. Renewable Energy Buyers Alliance, “Deal Tracker”, (last visited June 2020), online: <rebuyers.org/deal-tracker>
8. IESO, “Market Manual 12.0: Capacity Auctions” (16 September 2020), online (pdf): <www.ieso.ca/-/media/Files/IESO/Document-Library/Market-Rules-and-Manuals-Library/market-manuals/capacity-auction/Capacity-Auction.pdf?la=en>.
9. Despite the retirement of Ontario’s coal fleet, the procurement of over 4000 MW of near-zero marginal cost resources significantly contributed to decreasing the average hourly wholesale price.
10. Capacity markets were introduced to address the “missing money problem,” as it is known in the economic literature. The  main U.S. jurisdictions  where capacity markets were introduced are ISO-NE, PJM, and NYISO.
11. On June 4, 2020 the United Conservative Party reversed the previous government’s mandate to implement a capacity market, which ended the proceeding.
12. ENMAX Energy Corporation, “Rebuttal Evidence” (22 May 2019), online (pdf ): <www2.auc.ab.ca/Proceeding23757/ProceedingDocuments/23757_X0517.01_23757-X0517.012019-05-23RevisedRebuttalE_0877.PDF#search=23757%2DX0517%2E01> (AUC Exhibit Number 23757-X0517.01).
13. The current statutory framework is governed by the Electricity Act, 1998, SO 1998, c 15, Schedule A and Ontario Energy Board Act, 1998, SO 1998, c 15, Schedule B, as amended by the Electricity Restructuring Act, 2004, SO 2004, c 23, and Energy Statute Law Amendment Act, 2016, SO 2016, c 10.
14. The MENDM filed a proposed amendment in the Environmental Registry of Ontario to revoke Long-term Energy Plans, O Reg 355/17, which sets the timeframe for publishing the LTEP and is consulting on further changes: ero. ontario.ca/notice/019-2149.
15. IESO, “A Progress Report on Contracted Electricity Supply, Second Quarter 2020” (2020), online (pdf): <www.ieso.ca/-/media/Files/IESO/Document-Library/contracted-electricity-supply/Progress-Report-Contracted-Supply-Q2-2020.pdf?la=en>.
16. Ibid.
17. Ibid at 10.
18. For a full discussion on the OPA/IESO’s various contracts, see Ron Clark, Scott Stoll & Fred Cass, Ontario Energy Law: Electricity (Toronto: LexisNexis, 2012).
19. The contracted stipulated a Contingent Support Payment (CSP) from the OPA to the generator or a Revenue Sharing Payment (RSP) from the generator to the OPA depending on whether market revenues were sufficient and the generator performed in accordance to the contract.
20. For full compensation formula, see Clark, supra note 18.
21. The GA also covers costs related to OPG’s rate-regulated nuclear and hydroelectric generation resources, as well as conservation, demand management, and other provincial electricity programs.
22. This only includes HOEP and GA and excludes other costs such as uplift charges and any transmission and distribution-related charges.
23. Adjustments under section 25.33 of the Act, O Reg 429/04.
24. Similarly, Synapse Energy Economics study found that terms offered by competitive retailers are too short to support new capacity, see Hausman, supra note 4.
25. IESO, “Price Overview” (2020), online: <ieso.ca/power-data/price-overview/global-adjustment>.
26. IESO, supra note 2.
27. Originally announced as the Incremental Capacity Auction (ICA), which was subsequently removed from the scope of MRP and currently planned as an evolving Capacity Auction (CA).
28. IESO, “Annual Planning Outlook – A view of Ontario’s electricity system needs” (January 2020), online (pdf): <www.ieso.ca/-/media/Files/IESO/Document-Library/planning-forecasts/apo/Annual-Planning-Outlook-Jan2020.pdf?la=en>.
29. Ibid at 12.
30. Brian Rivard, “Don’t leave me stranded: What to do with Ontario’s Global Adjustment?” (July 2019), online (pdf): Ivey Energy Policy and Management Centre <www.ivey.uwo.ca/cmsmedia/3787293/dont-leave-me-stranded-what-to-do-with-ontario-s-global-adjustment.pdf>.
31. Power Advisory LLC & Aird & Berlis LLP, “Policy Case: Recommendations for an Ontario Load-Serving Entity Model” (September 2018), online (pdf): <energyontario.ca/wp-content/uploads/2018/09/OEA-LSE-Report-September-2018-Final.pdf> (Discussion paper prepared for the Ontario Energy Association).
32. IESO, “Electricity pricing” (2020), online: <www.ieso.ca/en/Learn/Electricity-Pricing/Global-Adjustment-Costs>.
33. Power Advisory LLC, supra note 27.
34. Although most contracts were awarded by the OPA/IESO through competitive procurement processes, the OPA/ IESO also took the position that it could enter directly into an agreement with a selected generator under certain circumstances. For example, Goreway Station and Portlands Energy Centre were entered into under a non-competitive process due to urgent local reliability issues.