Course: PPOL699: Competitive Policy

Assignment: 5000-words assignment to apply concepts and methodologies discussed throughout the course to an issue.

Title: Watts a Competitive Market? Electricity Prices and Renewable Energy Adoption in Alberta and British Columbia

Final Grade: A; 90%

Introduction

The Intergovernmental Panel on Climate Change’s (IPCC) Special Report on Global Warming of 1.5 ⁰C underscores the urgency of achieving global “Net-Zero”[1] greenhouse gas (GHG) emissions by 2050 [2], to mitigate the most severe effects of climate change. In response, nations worldwide are intensifying their pursuit of sustainable energy solutions to reach this “Net-Zero” target. Consequently, understanding how market structures influence electricity pricing and the integration of renewable energy has emerged as a critical area of study. This research seeks to address the pressing question: "How have competitive market structures impacted electricity prices and renewable energy adoption in Alberta and British Columbia?"

Alberta (AB) and British Columbia (BC) present unique cases in the Canadian electricity landscape. AB, having transitioned to a deregulated and competitive generation and retail market at the turn of the century, contrasts with BC’s vertically integrated and fully regulated market. This comparative study of these two provinces offers a compelling opportunity to explore how different market configurations can influence not only the electricity prices consumers face but also the integration and viability of variable renewable energy sources into the grid. Understanding the dynamics of market structures in relation to energy pricing and renewable adoption is essential for developing effective energy policies that balance economic efficiency with environmental sustainability.

Electricity System Overview

The transformation of electricity systems in Canada and globally is a focus point in contemporary energy research, driven predominantly by the rapid electrification of various sectors. This shift necessitates a substantial increase in electricity supply, with estimates suggesting that Canada may require a 62% to 135% increase in supply by 2050 [3, p. 64]. To address the rising demand and align with Canada's GHG strategy for achieving “Net-Zero” emissions by 2050 [4], it's essential to transition to low- or zero-emission electricity sources. This shift necessitates integrating variable renewable energy sources, alongside the deployment of smart grid technologies and distributed generation, as extensively discussed in existing literature [5]. These advancements offer significant opportunities for sustainability and efficiency, but also pose challenges in terms of capital expenditure and grid stability due to the reliance of intermittent energy sources; “the sun doesn’t always shine, and the wind doesn’t always blow” [6].

The electricity sector is a complex system composed of several key components that work together to ensure the efficient and reliable delivery of electricity to consumers. At its core are the utilities regulators, who are responsible for setting the rules of the electricity market, ensuring compliance with these rules, and protecting the interests of consumers. They play a crucial role in maintaining the balance between the needs of the electricity providers and the rights of the customers. Alongside the regulators are the system operators, tasked with managing and operating the electricity grid. They oversee the day-to-day functioning of the grid and plan for its future expansion to meet increasing demands. Additionally, the utilities form a fundamental part of the sector. These entities are involved in the generation, transmission, distribution, and sale of electricity to customers. They ensure efficient and safe production, transportation and deliver of electricity. The electricity market and its participants in AB and BC are summarized in Table 1.  

Table 1. Electricity Market Overview in AB and BC‡

 AlbertaBritish Columbia
Utilities RegulatorAlberta Utilities Commission (AUC)British Columbia Utilities Commission (BCUC)
System OperatorAlberta Electric System Operator (AESO) – IndependentBC Hydro – Crown Corporation
Utilities
GenerationCompetitive marketBC Hydro FortisBC and IPPs*80% 20%
TransmissionAltaLink ATCO Electric ENMAX Power Corp EPCOR Utilities50% 47% 2% 1%BC Hydro FortisBC92% 8%
DistributionATCO Electric ENMAX Power Corp Fortis Alberta EPCOR Utilities MunicipalitiesBC Hydro FortisBC Municipalities
Retail>40 regulated and competitive retailers (includes private companies and municipalities)BC Hydro FortisBC Municipalities
‡ Adapted from Table 1: Cross-province comparison of electricity industry composition [7, p. 10].
* IPPs = Independent Power Producers

</p>

BC represents a model of government-owned, vertically integrated utilities provider operating under fully regulated framework, where the government oversees all aspects of electricity services, including generation, transmission, distribution, and retail [7, p. 10]. This centralized control translates into a market where capital investments in power generation are predominantly limited to the provincial monopolies. As a result, a stable pricing environment emerges, with electricity rates set by the provincial regulator, ensuring long-term price consistency for consumers and maintaining predictability in a market typically characterized by natural monopolies. While the physical and financial constraints of building multiple transmission and distribution networks and the high capital costs of electrical generation facilities often justify the natural monopoly structure, many jurisdictions globally began transitioning away from this cost-of-service model in the 1990s and 2000s, driven by regulators’ efforts to promote market-based competition [8], [9, p. 677].

AB is one of those jurisdictions that have transformed its electricity market by deregulating its generation and partially deregulating its retail market [7, p. 10]. This deregulation leads to greater price volatility, as electricity rates in AB are primarily determined by supply and demand dynamics within the competitive wholesale market. Although transmission rates, regulated on a cost-of-service basis, and distribution rates, governed by performance-based regulation, remain fully regulated, the fluctuating overall electricity prices prompt wholesale customers to secure forward contracts [10, p. 3]. These are agreements to purchase electricity at a pre-set price for a future date, serving as a hedge against volatility. Generators that sell a forward contract and lock in the future price for their dispatchable capacity reduce their exposure to the real-time electricity pool prices, thereby lessening their incentive to exercise market power. Similarly, many retail customers choose fixed-price contracts to ensure rate predictability and mitigate risks associated with price volatility [11]. AB's market, characterized by its significant freedom, fosters innovation, and encourages investment in generation.

Claiming that electricity generation is a natural monopoly might oversimplify the efficiency comparison between BC's regulated system and AB's deregulated market. It's crucial to consider economies of scale relative to the size of the market. In larger markets, like those spanning an entire province and capable of supporting multiple generating plants, the generation sector might not display typical natural monopoly characteristics. This suggests that efficiency, in terms of both allocative and productive aspects, can vary significantly between different market structures and sizes. Therefore, while BC's model ensures price stability and predictability, it doesn't inherently guarantee superior efficiency compared to a system like AB's, where market mechanisms play a larger role.

The interplay between provincial and international (United States) markets impacts electricity pricing and market operations in both AB and BC. This is accomplished via interties that enable the import and export of electricity from neighbouring jurisdictions. There are three interties operating in AB with BC, SK, and Montana [12]. But the AB grid is relatively isolated as import capacity is equivalent to ~7.5% of installed internal generation capacity [13], [14]. While BC has two interties with AB and Washington capable of importing/exporting ~23% of installed internal generation capacity [13, p. 8].

Energy Market Structures

AB is the only Canadian jurisdiction with fully deregulated electricity generation and no provincially owned utilities provider [15]. Electricity prices are determined through hourly auctions with the lowest-cost power offers are selected each hour to match the load demands [16].Thereby the market is a single nodal price system, where all generators connected to the grid receive the same hourly price [8]. This is referred to as energy-only wholesale market (established in 2000) [17], generators earn revenue solely based on the electricity they produced and dispatched by AESO.

A significant aspect of this strategy was the creation and auctioning of 20-year Power Purchase Arrangements (PPAs) [16]. The holders of these PPAs gained the right to sell electricity from specific power plants up to 20 years. In turn, PPA holders managed the dispatch and sale of power, with an obligation to pay the power plant owners amounts predetermined in contracts. These contracts were designed to ensure that plant owners continue to receive their pre-deregulation rate of return. A key aspect of PPAs was their role in fragmenting offer control [18, p. 6], which limited or mitigated the market power of generators holding substantial generation capacity market share. This was essential for creating a more balanced and competitive generation market, preventing any single entity from exerting undue influence over prices.

Profitability for PPA holders depends on their ability to sell power at a profit. If they succeed, they retain the profits, which is what initially gave value to the PPAs. As an aside, in 2016 power prices declined and PPAs become unprofitable. Thereby PPA holders began withdrawing from these arrangements sparking a high-stakes dispute between the companies and provincial government, centering on the financial impact on AB ratepayers, which was estimated to potentially reach up to $2 billion [19]. This situation underscored the volatility and risks inherent in the energy-only market model.

The applicability of the PPAs were for legacy plant owners, thereby the energy-only market model doesn’t guarantee return on investment for generators coming online post deregulation. Most of the time offer prices are reflection of the variable costs, but there is no regulatory requirement that offers be made at or near variable cost and “limited” exercise of market power is considered “justifiable” [18], as it allows generators to recover fixed costs that are typically not recouped with prices set at short-run marginal cost. The limited exercise of market power thus ensures long-run investment efficiency for power plant investors. AESO and Market Surveillance Administrator (MSA) jointly share the responsibility of monitoring the market and the behaviors of all stakeholders to ensure compliance with the market power mitigation framework [18]. It is worth noting that market power is distinct from anti-competitive behavior which impede competition by creating, preserving, or enhancing market power [20].

The challenges and limitations experienced with the energy-only market model bring us to the discussion of capacity markets. In contrast to the energy-only market, a capacity market compensates generators for the ability to generate electricity on demand, even when not actively dispatching power [21]. This system ensures that generators are remunerated for their readiness and ability to respond swiftly to the electrical system's needs and generate power as required. This model is appealing to investors in generation projects, especially those owning thermal projects with higher fuel and carbon costs as they are capable of generating power on demand and can earn revenue when not actively dispatching electricity.

In 2016, AB’s NDP government announced based on recommendation from AESO that it would be transitioning from energy-only market to a capacity market by 2021 [22]. In 2019, the UCP government decided to cancel market transition plans and maintain an energy-only market due to its simplicity, proven track record in providing reliable and affordable electricity, and investor and stakeholder support [23]. It is worth noting that this was not the first time AB considered adopting a capacity market; in 2004 the province considered it but ultimately decided to maintain the simpler energy-only system [23]. These decisions highlight the ongoing debate and varied approaches in market design within the electricity sector.

BC’s regulatory controls over its energy markets have been shaped significantly by its challenging geography and demographics, the need to supply isolated communities and the strategic utilizations of its ample hydro resources [24]. The BC Power Commission was established in 1945 to consolidate smaller private utility providers and extend infrastructure to remote areas [24]. This effort led to the near-total amalgamation of the province's electric companies into the Power Commission. Today, BC Hydro provides electricity to about 87% of the province [25], while FortisBC handles natural gas and serves the remaining population. BC has recently begun to relax, introducing competition in natural gas and potentially electricity in the future [24].

Electricity Generation Investment

AB’s framework fostered significant investment in variable renewable energy generation [10]. Conversely, the stability and predictability of electricity prices in BC's regulated market are often highlighted, which ultimately leads to less renewable energy investment in BC as its mitigated with a stronger starting point comprised of 1,600MW of emitting assets constituting only 8% of its energy generation mix [7, p. 23]. While AB has 12,200MW of emitting thermal assets representing ~70% of the total generating capacity [7, p. 23].

AB's peak load occurs over the winter months [8], posing challenges for variable renewable energy policy as neither wind nor solar generation perform well during the coldest days of the year. While BC already relies heavily on its extensive hydroelectric resources to provide low-cost, low-emission, and reliable electricity. However, BC faces significant challenges in meeting future electricity demands, with additional major dams being unlikely, the province is exploring a mix of run-of-river hydro, solar, wind, and demand-side measures [7, p. 5]. Energy critics in BC highlight several significant challenges associated with major hydroelectric dams, which come with high financial costs and extended time frames for construction [26]. These challenges include detrimental effects on Indigenous practices (such as trapping, fishing and gathering), the release of toxic methylmercury that can accumulate in the food chain, and the flooding of fertile agricultural land [26]. Additionally, several recent Canadian hydroelectric dam projects (such as BC’s Site C) have been subject to cost over-runs which might render them uneconomic relative to alternatives [27]. Moreover, there is growing apprehension about GHG emissions associated with dams themselves, as studies have shown that methane emissions from hydro reservoirs can be significantly higher than previously estimated [28, p. 2]. Due to a unique legislative requirement for self-sufficiency in electricity production [29], BC cannot rely on imports to meet shortfalls, potentially leading to higher costs for consumers if domestic demand increases, especially in the context of a growing electrified LNG industry.

In terms of innovation, BC’s crown corporation power generators might exhibit x-inefficiency due to a lack of competitive pressure, a concept explored in depth by Harvey Leibenstein [30]. X-inefficiency is the inefficiency that arises due to the lack of competitive pressure, often observed in regulated or monopolistic markets. Conversely, a competitive market like AB’s generation is generally believed to reduce x-inefficiency due to the inherent pressure to innovate and improve efficiency to stay ahead of competitors. In a competitive environment, firms are constantly striving to reduce costs, improve product quality, and innovate to gain a competitive edge. However, it's important to note that the concept of x-inefficiency is sometimes dismissed by critics who argue that even in less competitive environments, other factors, such as regulatory standards, shareholder expectations, or the pursuit of long-term sustainability and reputation, can also drive firms towards efficiency and innovation, as observed in various empirical studies [30], [31].

AB’s deregulated energy-only, while open to technological and operational innovations, is susceptible to frequent changes in market rules and the potential for regulatory interference are seen as significant deterrents to investment [21]. This is particularly problematic in electricity markets where much of the revenue for capital investment depends on high spot market prices during a limited number of peak hours. The risk of regulatory actions preventing these prices from reaching appropriate levels can greatly undermine investment incentives. This issue is compounded by the competition among a few incumbents, making the market sensitive to policy changes. Historically, AB's electricity supply was dominated by coal, with natural gas plants and a minor contribution from renewables [32]. Post-deregulation, transitional mechanisms such as PPAs described earlier were implemented to manage the shift from the cost-of-service model [32]. Southern AB’s windy plains facilitated the growth of wind energy, initially supported by production incentives and favorable policies. However, wind energy growth stagnated around 2015 due to factors like price discounts, stagnant carbon offset prices, and the end of federal production incentives [32]. This context highlights the complexities and challenges of fostering renewable energy investment within AB's competitive electricity market.

Impact Assessment

Electricity Prices

Given BC’s fully regulated electricity market, it exhibited stable, long-term price consistency [7, p. 39]. This stability is due to the provincial regulator fixing rates based on the revenue requirements and operational costs of major utilities, including generation, transmission, distribution, and administrative activities. As previously mentioned, BC benefit from large-scale hydro resources, which, despite high upfront capital costs, offer low-cost electricity due to low operating expenses and near-zero variable costs in the long-run. Furthermore, government-owned utilities can tolerate lower returns and access cheaper government-backed debt contributing to lower prices [7, p. 41]. Additionally, BC derives significant revenue from power exports (especially to the United States where electricity prices are higher), aiding in offsetting domestic energy costs [7, p. 43].

In contrast, AB's deregulated competitive whole electricity generation market (known as Power Pool) leads to more volatile pricing. Prices in this market are determined real-time by supply and demand, fluctuating between the floor $0/MWh and the cap $999.99/MWh defined by AESO [7, p. 39], with a single hourly clearing price. Generators submit offers indicating the price at which they are willing to supply electricity to the grid, with the market operating on a merit order dispatch principle by prioritizing the dispatch of the lowest-priced offers to meet demand. This system, where AB operates under a single pool price, is subject to significant fluctuations, sending stronger investment signals during high-price periods and weaker ones when prices fall. This uniform pricing across the province relies on an uncongested transmission, separating the cost of electric energy from delivery expenses. Transmission and distribution fees are set by the Independent System Operator (ISO), transmission facility owners (TFOs), and distribution facility owner (DFOs) through regulated tariffs. Under the regulations, generators are required to offer all their available generation capacity to the market and cannot physically withhold it [10, p. 3]. However, they are allowed to engage in economic withholding by setting their capacity prices above the marginal cost. Consequently, a generator might not supply energy to the market until the market's marginal price rises sufficiently to match their offer, at which point the AESO dispatches it. To limit the degree to which sellers can exert market power, the existing market design imposes a cap on the maximum offer control share, ensuring that no single entity controls more than 30 percent of the supply share [10, p. 3].

Cross-border electricity trade exhibits distinct characteristics due to its dependence on an integrated wide-area transmission grid and its often-bidirectional nature [33]. Whereby a single jurisdiction might engage in both importing and exporting electricity within various time frames – over the course of a year, within a single day, or even simultaneously [33]. The primary motivation for importing and exporting electricity is the potential for profit through arbitrage opportunities [34, p. 19]. Under normal circumstances, electricity flows from markets where it has lower value to those where it commands a higher value, allowing the entities responsible for transferring the power to earn profits. This mechanism, which aligns with the principles of market efficiency, ensures that disparities in electricity prices between different markets are corrected over time, reflecting an efficient market outcome.

Factors influencing pool price fluctuations include offer behaviors, availability of low-cost renewable generation, power generation facility planned and/or unplanned outages, peak demand periods, and natural gas prices. Unlike BC, AB’s reliance on natural gas plants, which have higher electricity costs and are subject to volatile gas prices, contributed to its higher electricity prices by 70-80% relative to BC in 2022 as captured in Table 2. The absence of government-backed borrowing for private companies and AB's status as a net importer of electricity, lacking significant export revenue, further exacerbates cost challenges [7, p. 41]. Additionally, the competitive nature of AB's market, where firms sometimes exercise market power to sell above short-run marginal cost, has significantly impacted electricity prices, evidenced by a notable increase in peak hour prices in recent years [7, p. 41]. This trend is further substantiated by the MSA’s assessment, which found that the average hourly market markups in 2021 and 2022, as measured by the Lerner Index, were 0.37 and 0.36, respectively [35, p. 24]. The Lerner Index is a measure of market power indicating the extent to which generators set offer prices above marginal costs, ranging from 0 (perfect competition) to 1 (high market power).

Given that AB electricity prices are volatile, there are periods where AB prices are lower than BC. However, recent trends highlight a significant shift in this pattern particularly with the expiry of the 20 year PPAs on Dec 31, 2020 [36]. This event corresponded with a step change increase in the execution of AB generators market power. 63% of AB’s $70/MWh increase in average peak-hour prices from 2020 to 2021 was attributed to firms raising their offer prices above marginal cost. This surge in market power, linked to the expiry of the PPAs, was notable even when focusing on a narrow timeframe around the expiry event, during which there were no changes to the configuration of generation assets in the market [36]. Such trend underscores the complexity of AB's electricity market, where despite historical instances of lower prices compared to BC, recent developments have led to significant price increases driven by market power considerations.

Table 2. AB and BC Electricity Prices Comparison in 2022

Renewable Energy Adoption

AB’s deregulated market has fostered a significant increase in renewable energy investments, particularly in wind and solar power. In 2022, Canada increased its solar and wind generation capacity by 1.8GW, with more than 75% of it constructed in AB [37]. The energy-only market does pose a challenge for renewable energy adoption due to their intermittent nature. Renewable generators often make zero-dollar offers to ensure dispatch [38, p. 276], a practice historically used by baseload generators like coal to maintain continuous generation [39]. This strategy, while ensuring renewables are utilized when available, can lead to zero-dollar market events. These events impact the overall pool price and were a key factor in AB's consideration of transitioning to a capacity market (described earlier). There was a concern that the prevalence of zero-dollar events [40, p. 227], driven by intermittent renewables, might undercut the revenues of dispatchable sources, potentially leading to a situation where the market could not sustain enough dispatchable generation, risking bankruptcy for these generators. This was referred to as the missing money problem [41]. Interestingly, the current reality in AB contrasts this concern, as pool prices are often high, ensuring that all types of generators, both dispatchable and interruptible, are lucratively rewarded [36]. It is worth noting that AB is one of only two jurisdictions in North America that are energy-only wholesale markets, alongside Texas [23]. Most other jurisdictions in the US with electricity markets have implemented a hybrid model, incorporating both energy and capacity markets [23]. Capacity markets are known for their benefits, such as offering revenue certainty for investors, ensuring reliable generation, and reducing volatility in wholesale prices [23]. Despite these advantages, both energy-only and capacity markets have shown the ability to achieve high levels of reliability and attract new investment [23].  

In June 2015, the AB government initiated an expert panel to advise on climate change and renewable energy strategies, targeting 30% renewable electricity by 2030 through reverse auctions [42]. AESO was directed to develop a plan for new renewable electricity generation, considering the phase-out of coal generation and existing market structure. After examining various financial support mechanisms, including fixed payments and capacity payments, AESO recommended a contract-for-differences (CfD) approach for the Renewable Electricity Program (REP) [8]. The CfD method was chosen for its potential to remove merchant price risk for generators, lower financing costs, and effectively manage potential program costs. REP significantly increased the province's wind capacity by nearly 50% and triggered substantial private-sector development [8]. The REP's design attracted a wide array of potential projects and introduced new market participants, including targeted Indigenous equity participation [8]. Despite being canceled after three auctions in 2019, its indirect effects are still evident.

BC's reliance on hydroelectric power, backed by its regulated, government-owned utility, has resulted in a stable and less diverse renewable energy portfolio. Hydroelectric generation accounts for 87% of BC's total electrical output, while natural gas (5%), biomass (5%), and wind (3%), with solar generation being negligible [25]. As BC intends to achieve 100% renewable electricity [3], thereby new supply must be secured to replace natural gas generation and meet growing demand due to electrification. BC’s estimated unused waste biomass is equivalent to 20% of its fossil fuel consumption, offering a significant opportunity for partial decarbonization if utilized efficiently [25].

Generation investment in AB is influenced by prevailing pool prices, with escalating prices often attracting new investment provided that there are no barriers to entry (perceived or real). This market-driven approach allows private companies the flexibility and incentive to respond swiftly to market signals and to innovate. However, this responsiveness to market conditions also subjects them to higher risks associated with market volatility.

While in BC investment decisions are made by the regulator based on planning and long-term demand growth outlook. Crown corporations potentially exhibit x-inefficiency due to less market-driven agility but have the advantage of government backing. Allowing for long-term planning and potentially more significant investments in infrastructure and technology with less sensitivity to market fluctuations. This difference in risk tolerance and management can significantly influence the types of investments and the speed of innovation in different market structures.

Looking ahead, the prospects for renewable energy adoption in both provinces appear robust but will likely follow different paths. AB's ongoing commitment to a deregulated market suggests continued growth in diverse renewable sources, driven by market forces and technological advances. In contrast, BC may see a more measured but steady expansion of bioenergy utilization and renewable portfolio, as “there is no single ‘silver bullet’ renewable energy source to meet BC's GHG mitigation targets” [25].

Policy Implications

The policy implications for AB's energy market are multifaceted due to its unique position as one of the two North American jurisdictions with an energy-only wholesale market. The province's coal phase-out and shift towards renewable energy, aided by low natural gas prices, have set a precedent for significant energy transitions. However, the next steps towards full decarbonization, potentially leapfrogging or later phasing out unabated gas generation [32], present more complex challenges. Ensuring reliability in the face of increasing intermittent renewable generation necessitates developments like widespread adoption of storage resources such as Battery Energy Storage Systems (BESS) [43], reliance on thermal generation with carbon capture, overbuilding intermittent generation, or new technologies like hydrogen generation or small modular nuclear reactors (SMRs). AB’s recent developments, particularly in storage technology, indicate a promising trend towards integrating BESS with renewable projects, as seen in the rapid growth of storage facilities [44]. This surge capacity is necessary to manage the intermittency of renewable energy sources while maintaining a reliable grid for residential, commercial, and industrial consumption.  The integration of BESS in renewable projects introduces complexities in PPAs, necessitating considerations for payment mechanisms, control, performance guarantees, and operational requirements [43]. These developments, alongside legislative amendments like Bill 22 [43], indicate a shifting landscape in AB’s energy market, aiming to balance the integration of renewable energy with system reliability and market efficiency.

Similarly in BC, there is a lack of clarity on how to address the dual challenge of meeting growing energy demands while simultaneously achieving GHG mitigation targets. The CleanBC policy framework outlines action plans to meet BC's 2030 GHG goals, but in its current form it falls short in addressing the increasing energy demand due to population and economic growth, particularly in the building and industrial sectors [25]. To effectively achieve its 2030 targets, BC will need to not only reduce overall energy demand but also substantially increase the supply of renewable electricity and bioenergy. BC's policy efforts need to focus on creating more opportunities for renewable energy investments beyond its traditionally dominant hydroelectric sector. This could involve incentivizing solar and wind energy development and encouraging private investment in these areas. Additionally, like AB, BC could benefit from policies promoting technological innovations in energy storage, essential for managing the intermittency of renewable energy sources. Ultimately, the policy landscape in BC must adapt to ensure that the transition to a more sustainable energy mix is economically viable, environmentally sustainable, and consistent with the province's long-term decarbonization goals. This adaptation may include exploring new market mechanisms or regulatory frameworks to support the integration of diverse renewable energy sources while maintaining grid reliability and affordability for consumers.

Considering the evidence presented herein, to balance economic efficiency, market stability, and environmental targets, both provinces should explore hybrid models that combine the strengths of regulated and deregulated systems. This could involve regulated frameworks that offer stability and certainty for large-scale renewable project investors such contract-for-differences (CfD). Coupled with deregulated segments that spur innovation and competition in emerging energy technologies with greater financial rewards as generators could exercise a “limited” form of market power.

Conclusion

The examination of competitive market structures in AB and BC reveals distinct impacts on electricity pricing and renewable energy adoption. In AB, the shift to a deregulated, competitive generation and retail market along with several deliberate regulatory incentives has fostered innovation and investment in renewable energy, particularly in wind and solar power. This market, characterized by its volatility, is largely driven by supply and demand dynamics which encourages new market entrants at times of higher pool prices. The offer behaviours, exercise of market power and absence of significant export revenue at a premium have led to relatively higher electricity prices in AB compared to BC by 70-80%.

BC, with its regulated, government-owned utilities had a stable and predictable pricing environment, due to the provincial regulator's control over rate-setting. This regulated framework, while ensuring price consistency, could potentially foster x-inefficiency due to its limited market dynamics.  This stability, though beneficial for long-term pricing predictability, has led to less incentive for renewable energy investment beyond the dominant hydroelectric sector. Consequently, BC's energy portfolio heavily relies on hydroelectric power, which constitutes ~87% of its total electrical output. This reliance on hydroelectricity has led to a renewable energy mix with limited diversity, where contributions from other renewable sources like wind and solar are ~3% and nearly 0%, respectively.

The policy implications in both provinces are crucial. AB's deregulated market, despite encouraging renewable energy development, requires supplemental policies that provide stability and certainty for investors. This could include incentives for streamlined regulations for diverse energy source integration. Conversely, BC's policies might focus on diversifying its renewable energy investments, potentially through incentives for non-hydro renewable sources.

Both provinces could benefit from technological innovations in energy storage to manage the intermittency of renewable energy sources. AB's recent developments in storage technology, such as the integration BESS with renewable projects, offer promising trends for maintaining grid reliability and efficiency.

"How have competitive market structures impacted electricity prices and renewable energy adoption in Alberta and British Columbia?"

AB’s deregulated market has led to higher electricity prices but also a significant increase in renewable energy investments. BC’s regulated market, while offering cheaper and price stable electricity, has seen less renewable energy development outside its hydroelectric generation stronghold.

These contrasting experiences in AB and BC underline the complex interplay between market structures, energy pricing, and renewable energy adoption, offering valuable insights for sustainable energy policy development. Hybrid models combining the strengths of the regulated and deregulated models could be beneficial for both provinces.

References

[1]   Environment Climate Change Canada, ‘A Clean Electricity Standard in Support of a Net-Zero Electricity Sector Discussion Paper’, Mar. 2022. [Online]. Available: https://www.canada.ca/content/dam/eccc/documents/pdf/cepa/CleanElectricityStandardDiscussionPaper-eng.pdf

[2]   Intergovernmental Panel on Climate Change, Global Warming of 1.5°C: IPCC Special Report on Impacts of Global Warming of 1.5°C above Pre-industrial Levels in Context of Strengthening Response to Climate Change, Sustainable Development, and Efforts to Eradicate Poverty, 1st ed. Cambridge University Press, 2018. doi: 10.1017/9781009157940.

[3]   Canada, ‘Canada’s Energy Future 2023: Energy Supply and Demand Projections to 2050’, 2023.

[4]   Canada, Canadian Net-Zero Emissions Accountability Act, SC 2021, c 22. CanLII, 2021. Accessed: Nov. 25, 2023. [Online]. Available: https://canlii.ca/t/55zf5

[5]   M. H. Rehmani, M. Reisslein, A. Rachedi, M. Erol-Kantarci, and M. Radenkovic, ‘Integrating Renewable Energy Resources Into the Smart Grid: Recent Developments in Information and Communication Technologies’, IEEE Trans. Ind. Inform., vol. 14, no. 7, pp. 2814–2825, Jul. 2018, doi: 10.1109/TII.2018.2819169.

[6]   C. Van Kooten, ‘BLOG: “Renewable” energy can’t replace fossil fuels’, Fraser Institute. Accessed: Nov. 25, 2023. [Online]. Available: https://www.fraserinstitute.org/blogs/renewable-energy-cant-replace-fossil-fuels

[7]   B. Cooke and M. Orenstein, ‘Electricity Systems Across Western Canada’, Canadawest Foundation, Jul. 2023.

[8]   S. Hastings-Simon, A. Leach, B. Shaffer, and T. Weis, ‘Alberta’s Renewable Electricity Program: Design, results, and lessons learned’, Energy Policy, vol. 171, no. C, Dec. 2022, doi: 10.1016/j.enpol.2022.113266.

[9]   J. Monast, ‘Electricity Competition and The Public Good: Rethinking Markets and Monopolies’, Univ. Colo. Law Rev., vol. 90, no. 3, 2019.

[10] Alberta Electric System Operator, ‘AESO Market Pathways Primer’, Aug. 2023.

[11] S. Hastings-Simon and B. Shaffer, ‘The Regulated Rate Option Trap’. Accessed: Nov. 25, 2023. [Online]. Available: https://www.policyschool.ca/wp-content/uploads/2023/03/EFL-policy-trends-March.pdf

[12] Alberta Utilities Commission, ‘Annual Electricity Capacity, Total Generation and Interchange History’, 2022. Accessed: Nov. 23, 2023. [Online]. Available: https://media.www.auc.ab.ca/prd-wp-uploads/Shared%20Documents/2022-CapGenInterchange.pdf

[13] J. Maloney, ‘Strategic Electricity Interties’, House of Commons Canada, 2017.

[14] C. Thompson, J. Dudelzak, and K. Howie, ‘New Transmission Development in Alberta: AESO Focuses its Attention on Integrating Renewable Electricity’, BLG Insights. Accessed: Dec. 02, 2023. [Online]. Available: https://www.blg.com/en/insights/2018/02/new-transmission-development-in-alberta-aeso-focuses-its-attention

[15] K. Van De Biezenbos, ‘Lost in Transmission: A Constitutional Approach to Achieving a Nationwide Net Zero Electricity System’, Osgoode Hall Law J., vol. 59, no. 3, pp. 629–666, Oct. 2022, doi: 10.60082/2817-5069.3813.

[16] Alberta Electric System Operator, ‘Guide to understanding Alberta’s electricity market’. Accessed: Nov. 25, 2023. [Online]. Available: https://www.aeso.ca/aeso/understanding-electricity-in-alberta/continuing-education/guide-to-understanding-albertas-electricity-market/

[17] Alberta, ‘Energy in Alberta timeline’. Accessed: Nov. 25, 2023. [Online]. Available: https://www.alberta.ca/energy-in-alberta-timeline

[18] Alberta Electric System Operator, ‘Market Power Mitigation Advice to Minister’, 2019. Accessed: Nov. 25, 2023. [Online]. Available: https://www.aeso.ca/assets/Uploads/AESO-Market-Power-Mitigation-Report-Nov-29-2019.pdf

[19] A. Leach and T. Tome, ‘Power Play: The Termination of Alberta’s PPAs’, SPP Commun., vol. 8, no. 11, 2016.

[20] Canada, Competition Act, RSC 1985, c C-34. CanLII, 1985. Accessed: Nov. 25, 2023. [Online]. Available: https://canlii.ca/t/562tk

[21] P. Joskow, ‘Capacity payments in imperfect electricity markets: Need and design’, Util. Policy, vol. 16, no. 3, pp. 159–170, Sep. 2008, doi: 10.1016/j.jup.2007.10.003.

[22] P. Bryan, ‘Why Alberta Decided to Stick with its Energy-Only Electricity Market’, BLG Insights. Accessed: Nov. 25, 2023. [Online]. Available: https://www.blg.com/en/insights/2019/09/why-alberta-decided-to-stick-with-its-energy-only-electricity-market

[23] M. Ayres, ‘Electricity Market Design: Energy-only v. Capacity Markets’, The School of Public Policy. Accessed: Nov. 26, 2023. [Online]. Available: https://www.policyschool.ca/electricity-market-design-energy-only-v-capacity-markets/

[24] Energy Rates, ‘Why the British Columbia Energy Market is Regulated’, EnergyRates.ca. Accessed: Nov. 25, 2023. [Online]. Available: https://energyrates.ca/british-columbia/why-the-british-columbia-energy-market-is-regulated/

[25] H. Wang, X. Bi, and R. Clift, ‘Clean energy strategies and pathways to meet British Columbia’s decarbonization targets’, Can. J. Chem. Eng., vol. 101, no. 1, pp. 81–96, 2023, doi: 10.1002/cjce.24654.

[26] J. Wilt, ‘How 22 Hydroelectric Projects in Canada Put First Nations Communities at Risk’, Vice. Accessed: Dec. 03, 2023. [Online]. Available: https://www.vice.com/en/article/4w5nmj/hydroelectric-projects-pose-risk-to-first-nations-harvard-study-warns

[27] B. Dolter, G. K. Fellows, and N. Rivers, ‘The cost effectiveness of new reservoir hydroelectricity: British Columbia’s Site C project’, Energy Policy, vol. 169, p. 113161, Oct. 2022, doi: 10.1016/j.enpol.2022.113161.

[28] R. Hendriks, ‘Comparative Analysis of Greenhouse Gas Emissions of Site C Versus Alternatives’, Program on Water Governance, Jul. 2016. Accessed: Dec. 13, 2023. [Online]. Available: https://sitecstatement.files.wordpress.com/2016/07/1-site-c-comparative-ghg-analysis-report-final.pdf

[29] British Columbia, Clean Energy Act, SBC 2010, c 22. CanLII, 2010. Accessed: Nov. 25, 2023. [Online]. Available: https://canlii.ca/t/55k1g

[30] H. Leibenstein, ‘Allocative Efficiency vs. “X-Efficiency”’, Am. Econ. Rev., vol. 56, no. 3, pp. 392–415, 1966, Accessed: Dec. 05, 2023. [Online]. Available: https://www.jstor.org/stable/1823775

[31] M. Perelman, ‘Retrospectives: X-Efficiency’, J. Econ. Perspect., vol. 25, no. 4, pp. 211–222, Nov. 2011, doi: 10.1257/jep.25.4.211.

[32] B. J. Thibault, T. Weis, D. Leach, L. Mitchell, R. Acworth, and K. Havart-Crans, ‘Alberta’s Quiet but Resilient Electricity Transition’, in Sustainable Energy Transitions in Canada, 2023.

[33] W. Antweiler, ‘Cross-border trade in electricity’, J. Int. Econ., vol. 101, pp. 42–51, Jul. 2016, doi: 10.1016/j.jinteco.2016.03.007.

[34] Market Surveillance Administrator, ‘Alberta Wholesale Electricity Market’, Sep. 2010, Accessed: Nov. 30, 2023. [Online]. Available: https://www.albertamsa.ca/assets/Documents/Alberta-Wholesale-Electricity-Market-2010-09-29-v2.pdf

[35] Market Surveillance Administrator, ‘Quarterly Report for Q4 2022’, Feb. 2023, Accessed: Dec. 07, 2023. [Online]. Available: https://www.albertamsa.ca/assets/Documents/Q4-2022-Quarterly-Report.pdf

[36] D. P. Brown, A. Eckert, and B. Shaffer, ‘Evaluating the impact of divestitures on competition: Evidence from Alberta’s wholesale electricity market’, Int. J. Ind. Organ., vol. 89, Jul. 2023, doi: 10.1016/j.ijindorg.2023.102953.

[37] Canadian Renewable Energy Association, ‘Canada added 1.8 GW of wind and solar in 2022’. Accessed: Nov. 26, 2023. [Online]. Available: https://renewablesassociation.ca/news-release-canada-added-1-8-gw-of-wind-and-solar-in-2022/

[38] D. B. R. Johnson, M. Schneider, and Y. Liu, ‘Moving Forward by Looking Back: Toward a Renewable Conservation Scheme in Alberta’, Alta. Law Rev., pp. 267–267, Dec. 2021, Accessed: Nov. 26, 2023. [Online]. Available: https://albertalawreview.com/index.php/ALR/article/view/2674

[39] Market Surveillance Administrator, ‘Zero Dollar Offers’, Apr. 2003. Accessed: Nov. 25, 2023. [Online]. Available: www.alberta msa.ca/assets/Documents/Zero-Dollar-Offers-April-2003.pdf

[40] Alberta Electric System Operator, ‘Feedback on Key Provisions of the Renewable Electricity Support Agreement’, Dec. 2016. [Online]. Available: https://www.aeso.ca/assets/Uploads/2016-Stakeholder-Comments-RESA-Redacted-Feb-1-2017.pdf

[41] D. Newbery, ‘Missing money and missing markets: Reliability, capacity auctions and interconnectors’, Energy Policy, vol. 94, pp. 401–410, Jul. 2016, doi: 10.1016/j.enpol.2015.10.028.

[42] Province Takes Meaningful Steps toward Climate Change Strategy, (Jun. 25, 2015). Accessed: Nov. 26, 2023. [Online Video]. Available: https://www.youtube.com/watch?v=tzbKvRZE6hI

[43] S. Jeffers, I. Clarke, and Eeles, ‘Alberta’s Renewable Energy Market: Developing Contract Issues’. Accessed: Nov. 26, 2023. [Online]. Available: https://albertalawreview.com/index.php/ALR/article/view/2725/2672

[44] D. Eeles, M. Keen, A. Baer, and R. Taylor, ‘Energy Storage: The Regulatory Landscape in Alberta’, Alta. Law Rev., pp. 355–355, Dec. 2021, Accessed: Nov. 26, 2023. [Online]. Available: https://albertalawreview.com/index.php/ALR/article/view/2681