Ontario’s Electricity Market Woes: How Did We Get Here and Where Are We Going?

Ontario’s electricity market is materially different than the one envisioned when it opened in May 2002. In the lead-up to market opening, the electricity market was expected to provide competition, lower prices and transparent price signals to both consumers and investors.

Yet, over time, those principles became secondary concerns, overridden by new priorities that increased prices, reduced competition and distorted price signals.

Ontario again redesigning its key components of its electricity market in an effort to make good on a number of the promises made in 2002. This report provides a guideline to both what went wrong and whether these issues will be addressed going forward.

PART I: THE RISE AND FALL OF PUBLIC POWER IN ONTARIO

The story of Ontario’s electricity market really begins in 1906.

It was then that the Hydro Electric Company of Ontario (HELCO) — or “Hydro” — was founded by the province and led by Adam Beck. While Hydro was established to build, own and operate a transmission network to deliver power across Ontario, it quickly broadened this vision to include the construction of hydroelectric dams.[1] The mantra of Hydro was to deliver, “power at cost.”[2]

Hydro eventually came to take over the entire electricity sector, but not without controversy. By the 1920s, after a series of cost overruns at one of its largest generation projects — the Queenston-Chippawa Generating Station (later renamed Adam Beck 1) — Hydro’s debt accounted for more than one-half of the province’s total debt.[3] One commission in 1924 found that many of Hydro’s construction projects were unjustifiably elaborate and costly.[4]

But with Hydro’s importance to the growing electricity sector and the provincial economy firmly established — as well as remaining popular with the public at large — Hydro’s economic and political influence grew stronger.

Demand for power continued to grow year-over-year and decade-over-decade, leading Hydro— officially transformed into a crown corporation in the 1970s and renamed Ontario Hydro — to expand its generation fleet beyond hydro dams. In the 1950s and 1960s it began construction on a series of large coal generators, such as the Lakeview generating station — the largest coal plant in the world at the time.[5]

By the 1970s, Ontario Hydro began construction on a series of nuclear generators, bringing the four-unit Pickering Generating Station into service in 1971, the first large-scale nuclear plant in Canada. In the 1970s and 1980s, Hydro built the four-unit Bruce Generation Station (Bruce A), four more units at Pickering (Pickering B) and another four units at Bruce (Bruce B). In 1990 — after years of delays and billions of dollars in cost overruns — Ontario Hydro completed the four-unit Darlington Generating Station, fully transforming itself into a predominately nuclear utility.[6] By 1992, its nuclear fleet accounted for 53 per cent of total output.[7]

Ontario Hydro’s nuclear ambitions stood in stark contrast to its financial health. When the Darlington plant was completed in 1991, Ontario was suffering from a severe economic recession, yet Ontario Hydro was pushing for a 40 per cent rate increase.

At the time, Ontario Hydro’s debt amounted to more than one third of the province’s total indebtedness. The financial deterioration culminated in a series of write-downs. First, a $3.6 billion write down in 1993 and later a $6.6 billion write down in 1997.[8] These were the two largest write downs in Canadian corporate history. In 1993, the province implemented a rate freeze that was to remain in effect for the remainder of the decade and into 2002.[9] By the end of the 1997, eight of Ontario Hydro’s 19 nuclear reactors were shut down due to poor performance and safety issues.[10]

Ontario Hydro’s reputation, like its finances, was teetering on the brink of collapse.[11]

One of the biggest problems facing Ontario Hydro was that it overbuilt the grid on the assumption that electricity demand would continue to grow, as had occurred throughout the 20th century. In the late 1980s, Ontario Hydro forecast demand would hit 184 TWh by 2000 — nearly 20 per cent higher than actual demand of 153 TWh in that year and more than 50 TWh higher than demand in 2017.[12] In the short-term, Ontario Hydro expected demand to reach 159 TWh in 1994, even though actual demand turned out to be 135 TWh.[13]

In short, the utility had too much supply and too little demand.

Given that many of Ontario Hydro’s costs were fixed, lower demand increased the average cost to be recovered for each unit of power generated. The result was Ontario Hydro asking for a 40 per cent rate hike in the midst of a recession. A public reckoning on the fate of public power took hold.[14]

By 1999, Ontario Hydro’s reign as the province’s electricity monopoly was officially over.

In the end, Ontario Hydro was left holding $38.1 billion in debt and other liabilities, with more than half of that amount — $20.9 billion — unsupported by the value of its assets. Ultimately, $7.8 billion of that debt was unable to be paid down from future revenues and was collected from ratepayers in the form of a monthly charge known as the Debt Retirement Charge, which remained in effect until April 2018.[15]

PART II: BREAKING UP (ONTARIO HYDRO) IS HARD TO DO

Ontario Hydro’s financial demise shook the provincial legislature and economy. It also coincided with a push in the 1990s — both in Ontario and jurisdictions around the world — to deregulate the energy sector and transition to one based on competition and market principles, rather than a government-owned, top-down public utility model.[16]

In 1995, an Advisory Committee — known as the Macdonald Committee — was established to “study and assess options for phasing in competition in Ontario’s electricity system.” The committee called for an end to Ontario Hydro’s monopoly on generation, an independent transmission network open to private generators, an independent system operator and a new regulatory structure to oversee the sector and allow for greater independent oversight. It also called for full retail and wholesale competition. The report was a stark break with the last century of Ontario Hydro’s dominance.

The committee’s recommendations paved the way for the eventual breakup of Ontario Hydro in 1999 into five parts — Ontario Power Generation (OPG), Hydro One, the Independent Market Operator (later renamed the Independent Electricity System Operator), the Electrical Safety Authority (ESA) and the Ontario Electricity Financial Corporation (OEFC). One key recommendation was that Ontario Hydro’s generation division be split into various units and required to compete against one another. The report called for the nuclear unit to be split into competing entities, the hydroelectric stations to be grouped by river system and the thermal units to operate as distinct entities.

By 1997, the Government of Ontario issued a white paper laying out its vision for the electricity sector — stopping short of adopting the full list of recommendations from the Macdonald Committee. While the white paper called for splitting Ontario Hydro into a generation business and a transmission and distribution business, the generation business — comprising of nuclear, hydroelectric and thermal generators — would remain under public ownership and control nearly the entire market.

By 1998, the Government of Ontario passed Bill 35, the Energy Competition Act — which included the Electricity Act and the Ontario Energy Board Act — that formally laid out the breakup of Ontario Hydro. It also provided the Ontario Energy Board greater power in setting rates, among other changes.

The end of Ontario Hydro was complete.

The underlying theme in both the Macdonald Committee and the subsequent white paper was that a “competitive” electricity system would overwhelmingly benefit the province and its ratepayers by reducing prices. The push for deregulation was supported by a number of key industry players, notably the Association of Major Power Consumers in Ontario (AMPCO) and Independent Power Producers’ Society of Ontario (IPPSO).[17] Small volume customers (largely households) appeared eager to participate in the competitive retail market, with nearly one million of Ontario’s more than four million electricity customers having signed contracts with various retail intermediaries by the time the market opened in 2002.

While the market was initially scheduled to open in 2000, that date was subsequently pushed back to May 2002.

Other changes were also introduced in an effort to reduce OPG’s market power, as it continued to own and operate nearly 90 per cent of the generation assets in Ontario. In an attempt to reduce the public utility’s market power, the Market Power Mitigation Agreement (MPMA) was introduced in 1998.

The MPMA contained two key proposals. First, it capped the price paid to OPG on 90 per cent of its domestic sales at 3.8 cents per kWh. Anything above that amount — if wholesale prices were greater than 3.8 cents per kWh — would be rebated to Ontario consumers. Secondly, within ten years of the market opening, OPG would reduce its generating capacity to no more than 35 per cent of Ontario’s total capacity. OPG would also reduce its control of price setting, or marginal, generating plants to 35 per cent of the province’s total within 42 months.

In July 2000, OPG agreed to an 18-year lease with a private consortium to operate its four Bruce B nuclear units. OPG hailed the lease as “a major initial step” in meeting the terms of the MPMA.[18] In 2002, OPG also sold four hydroelectric generators with a total capacity of 490 MW.[19]

Yet, contrary to the MPMA, OPG’s market power was never reduced to the levels imagined prior to market opening. In 1999, for example, OPG moved forward with its decision to bring the four Pickering A units back into service. By 2012 — ten years after the market opened — OPG’s in-service generation capacity remained at 53 per cent.[20] In 2005, it still owned as much as 72 per cent of installed capacity in Ontario.[21] OPG continues to own and operate around 50 per cent of installed capacity.

PART III: ONTARIO PULLS BACK FROM DEREGULATION

In May 2002, after a near two-year delay, the market opens.

But just as quickly as the market opened, the province passed legislation freezing retail prices at 4.3 cents per kWh for the next four years.[22]

While the wholesale market continued to operate as planned, the price freeze directly undermined the price signal that a deregulated energy market was intended to send to consumers. Because the freeze was applied retroactively to May 2002, it also undermined the decision of the more than one million consumers to sign fixed contracts with private retailers.[23] In its first major review of the electricity market, the Market Surveillance Panel (MSP) highlighted that the price freeze “removed any incentive…to conserve energy and clearly resulted in inefficient consumption decisions.”

Initially, the price freeze was intended only for small-volume customers. But by March of 2003, the province expanded the price freeze to include most small businesses. Eventually, customers covered by the price freeze accounted for more than half of all power consumed in Ontario.

The price freeze proved costly for the province. The rebate covered the difference between wholesale prices and the level determined by legislation. In the year following market opening, the average wholesale price was 6.2 cents per kWh — or 44 per cent higher than the legislatively mandated retail freeze. The cost of that difference — financed by the provincial agency — the Ontario Electricity Financial Corporation (OEFC) was approximately $730 million in the first year.[24]

So what went wrong?

There were two main factors that pushed prices higher. First, 2002 had an exceptionally hot summer, leading to higher than anticipated demand. Second, the market was hit by a number of supply issues, both expected and unexpected, that resulted in a supply shortage. When the market opened in May 2002, the average wholesale price was 3.01 cents per kWh, rising to 3.71 cents per kWh in June. By July that figure hit 6.2 cents per kWh, soaring to $1.03 per kWh — or $1028.42 per MWh — in one hour in September.[25] Nonetheless, prices in Ontario during the month of May and June were actually lower than most neighbouring jurisdictions, while they were slightly higher in July and August.[26]

Higher temperatures meant higher demand — with AC usage having transformed Ontario from a winter peaking jurisdiction to a summer peaking one. Energy demand grew around 1.6 per cent annually between 1984 and 2001, but jumped by 5.5 per cent in 2002.[27] High temperatures and dry weather conditions also lowered the amount of water available to power the province’s fleet of hydroelectric generators.

The surge in demand and subsequent supply shortage was initially unexpected.[28] Just one month prior to the market opening, the Independent Electricity Market Operator (IMO) noted that, “[b]ased on existing and proposed facilities, Ontario is expected to have reliable supply of electricity for the 10-year period under a wide variety of conditions.”

For years, Ontario had a surplus of power. Generation capacity was nearly 20 per cent higher than peak demand in 1996, but by the summer of 2002 it had fallen to a 1.5 per cent power deficit, which was met by imports from neighbouring jurisdictions. The power deficit saw the IMO issue multiple power warnings over the summer, urging consumers to cut demand.

Ontario was also facing a number of supply issues, although many of these issues had been evident for years prior to the market opening. Combined with these known supply issues were a number of unexpected outages.

For starters, a large portion of the province’s nuclear fleet remained offline. Between 1995 and 1998, both the Bruce A and Pickering A nuclear reactors, which amounted to around 3,000 MW and 2,000 MW of capacity, respectively, were taken offline for a variety of performance and safety issues noted in a 1997 assessment of Ontario Hydro’s nuclear assets.

In 1999, OPG announced its decision to bring the Pickering A units back to service — at an initial cost of $840 million, but eventually completed for an estimated $3 to $4 billion — with the first unit expected to be back in service by 2001. The last of the four units was expected to be back online by the end of 2002. The reality was that the first of the four Pickering units did not come back online until late 2003. OPG later decided not to refurbish two of the four units due to cost concerns.[29] The delays at Pickering created a giant hole in the province’s supply mix.

Nonetheless, these supply issues were known before the market opened.

There were also a few unexpected delays, although they were minor in scale. Hydro One had expected to increase its intertie capacity at the Michigan border by 500 MW by the summer of 2002, but that work was delayed.[30] One of the nuclear units at Bruce B (unit 6) was also unexpectedly offline, removing a slice of the generation mix in August when demand in the province was at its peak.

Surging wholesale prices produced a public backlash when the market was in its infancy. In response, the province intervened in letting the market dictate prices at the exact moment the market was providing the right signal — high demand and a shortage in supply pushed prices higher, as market theory predicted. The province’s price freeze, in contrast, encouraged more consumption at a time of power deficits.[31]

The MSP found that, while prices in Ontario spiked as a result of a surge in demand and reduced supply, wholesale prices over the summer were largely in line with neighbouring jurisdictions that also operated a wholesale market. Off-peak prices in Ontario were, in six of nine months in 2002, actually lower on average compared to neighbouring markets.[32] The surge in peak prices, particularly in August and September, was a clear signal to consumers that supply conditions in Ontario were tighter than initially anticipated. The price freeze undermined this signal.

In the run-up to market opening, investors also remained skeptical of the province’s enthusiasm for a competitive market. For starters, there was a near two-year delay in the market opening. Secondly, up until 2001, OPG had not divested any of its assets, as was intended by the mitigation agreement. Thirdly, from 1999 to 2001, OPG had actually increased its market power with its decision to return the four units at Pickering A to service. Fourthly, in 2000, the province announced a freeze on the sale of OPG’s coal-fired units for environmental reasons — maintaining OPG’s market power. By 2002, the province fully blocked the sale of two of OPG’s coal-fired units. In 2002, Sithe Energies announced it was suspending plans to build two power plants — even though it had already been granted regulatory approval — citing OPG’s continued market power and changing government policy as two reasons.[33]

The price freeze implemented by the province months after the market opened simply put a further chill on the sector. An executive at one of Canada’s largest private power utilities called the price cap a “recipe for disaster.”[34] Other investors said they were reluctant to invest in the sector until the Pickering A units were back online and its impact on wholesale prices was clear. One industry executive noted bluntly:

“I can’t see any generators wanting to invest in this province.”[35]

While the price freeze announced in 2002 was expected to be in place until 2006, it proved too expensive for the province. In April 2004 the price cap was raised to 4.7 cents per kWh on the first 750 kWh of consumption and 5.5 cents for each unit above that threshold. By April 2005, the price cap was raised once again to 5 cents on the first 750 kWh and 5.8 cents for each unit above that threshold. By November of 2005, OPG’s nuclear and baseload hydroelectric units were placed under full OEB regulation.

Nonetheless, even without the legislative intervention that would come to dominate later in the decade, the electricity market suffered from design flaws right from the start. These shortcomings included: the lack of location-based prices (Ontario instead implemented a uniform price across the province), OPG’s continued market dominance in wholesale market and system operator intervention. A number of these issues remain in place to this day.

PART IV: THE HYBRID STRUCTURE TAKES HOLD

The election of a new government in 2003 ushered in a new era in the province’s electricity sector. While the new government maintained the wholesale electricity market, it introduced legislation that reduced competition by establishing a provincial-led agency to procure new generation, among other policies. In time, the provincial agency responsible for new supply would be the sole source of new generation in Ontario and nearly all generators would be incented by some form of out-of-market payment.

The so-called “hybrid” market was now in full swing.

The hybrid market’s establishment is most tied to the passing of Bill 100, the Electricity Restructuring Act (2004), which created the Ontario Power Authority (OPA), established rate regulation for a majority of OPG’s generating assets and mandated the annual setting of retail rates for customers by the OEB.[36] The province also abandoned the MPMA.

At the time of the bill’s passing, there had been little new private sector investment in the sector and, as a result, almost no new competitive generation added to the grid. The biggest chunk of new capacity came from the completion of OPG’s Pickering A return to service. The province was expecting a power deficit in the coming decade.[37]

Yet, the combination of rate regulation for OPG, and a provincially run procurement agency established to sign guaranteed contracts with generators, meant that the private sector would only invest in the province if it was through the government of Ontario or its agencies. The MSP warned in 2005 that “it is unlikely that any generator would choose to build new supply without contractual guarantees.”[38] It pointed out that even the limited number of private sector generators that had recently decided to invest in the province when there was no government help had, in the wake of the establishment of the OPA, negotiated contracts with the provincial agency.

And finally, the setting of retail rates by the OEB undercut the retail market while also further removing the “market” rate for power from the price paid by consumers. In essence, nearly all small volume customers had been moved to a retail agreement with the OEB acting as the de facto retailer.

The OPA quickly went from an independent agency overseen by the regulator to one overseen by the Ministry of Energy. The OPA’s primary role was to plan and procure new generation capacity in the province, as well as oversee conservation programs. As part of that process, the OPA was required to submit a long-term supply and demand forecast — known as the Integrated Power System Plan (IPSP) — to the OEB for review every three years. The OEB would then hold a hearing to determine whether this plan and forecast was economically prudent and cost-effective, among other criteria. The first IPSP was scrapped midway through the review process due to a directive from the Minister of Energy to include more renewable generation. The second IPSP hearing was never held. The IPSP process was eventually replaced by the Long-Term Energy Plan (LTEP) overseen and published by the Ministry of Energy. The future of new supply in Ontario was now laid out by the Ministry of Energy and procured through its contracting agency without regulator review.[39]

The establishment of the OPA, combined with the province’s decision to phase out coal generators and growing demand forecasts, resulted in a rush of new capacity. By 2005, the province announced that it had agreed or was negotiating the procurement of more than 9,000 MW of new capacity — nearly four times the 2,200 MW of capacity that was built between 2000 and 2003.[40] Nearly all of the contracts signed between the OPA and generators were 20 years in length.

More importantly, between contracts with OPA, OPG’s continued market dominance and the decision to rate-regulate OPG’s baseload assets, nearly all investment in the province was being shielded in some part from the wholesale market.

Nonetheless, in 2005, the OPA announced that the “hybrid” market was “intended to migrate toward a competitive structure.”[41] The Minister of Energy at the time criticized previous policies that had artificially lowered the price of power.

“For too long, taxpayer subsidies have kept electricity prices unsustainably low,” then Minister of Energy Dwight Duncan said. “We are easing the burden on taxpayers, while ensuring electricity prices for consumers are stable and competitive with nearby jurisdictions.”[42]

But that migration never occurred.

PART V: ONTARIO’S ELECTRICITY SECTOR GOES GREEN

Ultimately, the transition from a hybrid market towards a competitive market took a backseat to renewable energy policies.

Those ambitions took centre stage with the passing of the Green Energy and Economy Act (GEA) in 2009. The objective of the GEA was to encourage the rapid development of renewable energy projects by, most notably, introducing a feed-in-tariff (FIT) that would pay renewable generators an above-market, guaranteed rate for the next 20 years.[43]

The GEA also altered the governance and regulatory structure of the electricity sector by bestowing more legal powers on the Minister of Energy, allowing, for example, the Minister to decide whether a competitive or non-competitive process should be used in procuring new capacity.[44] The legislation also allowed the Minister to set prices, as well as limit the ability of the OEB to act independently of the Province’s renewable energy policies by determining they are uneconomic.[45] Going forward, all costs related to renewable energy were to be automatically approved by the regulator. The feed-in-tariff rates paid to renewable generators were well above market rates and were determined by the legislature, not the market.[46]

The GEA wasn’t the province’s first move towards integrating renewable energy into the grid, it was simply a more pronounced one. In 2004, the OPA announced the first round of a competitive Request for Proposals (RFPs) for renewable energy, known as the Renewable Energy Supply (RES) program. It later launched further auctions in 2005 and 2007, known as RES II and RES III. In total, the RES program introduced 1,570 MW of new wind capacity at a cost of between 8 and 9 cents per kWh.[47] Other renewable energy procurements were also undertaken.

The Green Energy Act pushed the province’s renewable energy ambitions to a new level. Nearly 15 years after the province first announced its move towards renewable energy, Ontario’s electricity grid had been transformed. By the end of 2017, Ontario had signed contracts with wind and solar generators amounting to 5,533 MW and 2,681 MW of capacity, respectively.[48]

Ontario’s coal generators have also been forced into early retirement and replaced, largely, with natural gas generators. The Independent Electricity System Operator (IESO), which was merged with the OPA in 2015, has signed contracts with gas generators amounting to 9,458 MW of capacity.[49]

In total, the IESO has signed more than 33,000 contracts with a variety of generators — ranging from large-scale natural gas generators to rooftop solar panels.

The province now also has a significant surplus of power.[50] In part, the reason that ratepayers now pay more than they did a decade ago for each unit of power they consume, even though the wholesale price has declined, is that a greater portion of their bill relates to fixed costs associated with contracted and regulated rates. These fixed costs are largely recovered through the Global Adjustment charge.

Apart from transforming the mix of the province’s generation fleet, the renewable transformation also increased Ontario’s installed grid connected generation by more than 20 per cent from 31,189 MW in 2007 to 37,044 MW today. [51] Ontario has more installed generating capacity than it did a decade ago, even though demand for power has declined over that time.

PART VI: INTERVENTION BEGETS MORE INTERVENTION – ONTARIO’S ELECTRICITY MARKET IS SHAPED BY LEGISLATION AND DIRECTIVES

Ontario’s electricity market— and the agencies that oversee and regulate it — has increasingly been shaped by directives from the Ministry of Energy, rather than market-based, competitive forces.

The intervention is most clearly laid out in the number of directives issued to the OPA, IESO and the OEB since 2005. In total, there have been 114 directives issued to these agencies between 2005 and 2015. Nearly all generators now receive a fixed or contracted rate for their output and many consumers, both large industrial users and small-volume household customers, pay a price that is, in part, determined via legislation, not the wholesale market.

Directives are just one method of legislative intervention. In 2016, the province passed legislation transferring all electricity planning responsibility to the Ministry of Energy through the LTEP.[52] The LTEP process ensures the legislature, through the Ministry of Energy, is the final arbiter of what investment will occur in the province. It’s not clear what aspects of the LTEP process will continue in the future.

The Ministry of Energy now also decides what large transmission projects will get approved, whereas that power previously resided with the OEB, which would hold a public hearing to determine whether it was economic.[53]

The province passed legislation approving the Darlington Refurbishment Project (DRP), a $12.8 billion project to extend the life of the site’s four reactors.

The result of legislature intervention has created further divergence between the price ratepayers pay to consume power and prices on the province’s wholesale market. The difference between the wholesale market price and the rate guaranteed to generators that either have a contract with the IESO or have rates set by the OEB is made up through the Global Adjustment. The Global Adjustment and the wholesale market price — known as the Hourly Ontario Energy Price (HOEP) — are inversely related. A lower market price reduces revenues to generators, which then increases the Global Adjustment charge in order to make generators whole and cover rates set via contracting or rate regulation. Over time, as more generators had their costs set by contracting or rate regulation, the Global Adjustment has grown substantially and now accounts for a majority of the cost of generation and price paid by consumers.

With a surplus of generation in Ontario selling power on the wholesale market below their contracted rate and, in many cases, at a low marginal cost — as they now receive more money through the Global Adjustment charge than wholesale prices — prices have dropped dramatically. The average wholesale price in 2017, for example, was the lowest since the market opened in 2002. Wholesale prices are, in many cases negative, even during periods of high demand.

Over time, as more contracted power was added to the electricity system, costs also increased. Overall system costs increased from $8.3 billion in 2006 to $13.7 billion in 2017, marking a 65 per cent increase.

As system costs increase, so too did prices for consumers, particularly for low-volume consumers such as households and small businesses. Nearly all small-volume consumers now have their rates set biannually by the OEB. Between 2006 and 2017 — prior to the passing of the Fair Hydro Plan — the off-peak electricity rate increased nearly 150 per cent for households across the province.

The public became increasingly concerned over electricity rates.[54] In response, the province implemented a series of policies that either shifted costs to the tax base, future ratepayers or between small and large volume customers — or some combination of the three.

  • In 2011, the Clean Energy Benefit, provided small-volume consumers with a 10 per cent rebate on their monthly electricity bill.[55]
  • Also in 2011, the Industrial Conservation Initiative (ICI) split Ontario ratepayers into two classes for the collection of Global Adjustment costs: Class A (large volume customers) and Class B (small volume customers). Class A consumers pay Global Adjustment charges based on their demand during peak hours — lowering those costs for the entire following year. These costs are shifted to Class B customers. Since the policy was implemented, nearly $5 billion in costs have been shifted from Class A to Class B customers.
  • In 2017, the Fair Hydro Plan (FHP) reduced electricity bills by 25 per cent for small customers by, most notably, using long-term debt to lower Global Adjustment costs, among other policies.

By 2017, prices in the wholesale market became just a small portion of the actual cost of generation due to the policy of signing long-term contracts with generators. The price signal — considered one of the key components to the wholesale market when it opened in 2002 — has been distorted.

PART VII: DEMAND FALLS WHILE SUPPLY INCREASES

In hindsight, Ontario built out its generation capacity at the exact moment that demand began a decade-long decline. And because many of the costs in the generation sector are fixed — either through regulated rates set by the OEB for OPG’s output or fixed-price contracts — any reduction in demand pushes up the price of each unit sold. Demand in Ontario fell from its high of 157 TWh in 2005 to 132.1 TWh in 2017 — a near 16 per cent decline.

This decline in demand stands in contrast to forecasts made in 2005 calling for years of growth. Similar to what occurred with Ontario Hydro in the 1980s and into the 1990s, the early demand forecasts laid out by the OPA turned out to be too high. In 2007, when the OPA submitted its first supply plan to the OEB, it predicted that demand in Ontario would grow to 165 TWh and 176 TWh by 2015 and 2020, respectively.[56]

Demand fell for a variety of reasons — an increase in embedded generation, a greater emphasis (and success) at energy conservation and a severe economic downturn in 2008-09. Embedded generation — largely made up of renewable generators that provide their power to local distribution companies (LDCs), as opposed to being connected to the provincial transmission grid — has increased from 1.7 TWh in 2006 to 6.3 TWh in 2017 and continues to grow. Conservation programs have also helped to reduce electricity demand by nearly 9 per cent between 2006 and 2016.[57]

More importantly, the rise of a directive-based electricity sector constrained the market’s ability to respond to falling demand. The directives that have been issued in Ontario are largely static tools that simply told the agencies overseeing the electricity sector what to do — procure more renewable energy or demand response, for example. But when conditions in the province’s electricity market changed — such as a reduction in demand — these static directives became out of date and, in most cases, worked against efficiency in the market. More directives must eventually be introduced to counteract the effect of previous directives. In response to falling demand, a truly competitive market may have curtailed investment and limited Ontario’s energy surplus.

Contrary to responding to a surplus by curtailing investment, the exact opposite occurred in Ontario over the last decade. In total, the OPA forecast that the province would have a generating capacity of 34,008 MW in 2017 from its 2007 level of 31,214 MW.[58] Yet, over the next decade, the Ontario’s generation fleet grew to its current level of 37,555 MW (not including behind-the-meter generation which totals more than 3,000 MW), while demand fell from its 2005 peak of 157 TWh to 132 TWh in 2017.

PART VIII: BACK TO THE FUTURE WITH MARKET RENEWAL

The deficiencies in Ontario’s wholesale electricity market are well-known and long-standing. These deficiencies have been exacerbated by legislative directives and policies since the market opened — even if some of those policies may have been merited for social and environmental reasons.

But change is in the air.

The IESO is now working on a coordinated set of reforms, known as the Market Renewal Program (MRP), in an attempt to address many of these deficiencies. These reforms include, among others, the move to locational pricing, a technology neutral capacity auction and financially binding day-ahead market. The IESO recently released a number of detailed design documents as part of the next stage of MRP.

Nonetheless, a number of concerns have already arisen with the MRP. Notably, the IESO has reduced the scope and impact of the project— lessening the financial and efficiency benefits that it will provide ratepayers. Early estimates suggested the cost of implementing MRP was $200 million, while producing $3.4 billion in benefits between 2021 and 2030.[59] But that benefits forecast has been lowered to around $500 million.

The reduced financial benefit is the result of a number of key changes made to the MRP by the IESO.

For starters, in response to feedback from stakeholders, the IESO will scrap locational (or zonal) pricing for most consumers and continue with a provincial-wide uniform price. Locational prices were expected to address a key inefficiency in the design of the wholesale market — leading to a more efficient use of Ontario’s high-voltage transmission network, more efficient consumption and targeted generation investment in areas where it’s most needed. While some of these benefits will still accrue due to locational pricing for generators, consumers will continue to be shielded from a transparent price (i.e., the true cost) of their consumption. Cross subsidies will continue to flow from one class of consumers to another as a result.

Second, the IESO has put on hold the Incremental Capacity Auction (ICA) and replaced it with a more modified capacity auction – which has since been further delayed as a result of the COVID-19 pandemic. The ICA was responsible for more than $2 billion of the $3.4 billion in benefits from the MRP. Nonetheless, even capacity auctions, while competitive when viewed at face value, may also result in large scale over procurement, as has been the case in a number of US jurisdictions. Additionally, the IESO noted that the capacity auction may be supplemented by further contracting — once again introducing the risk of repeating one of the major concerns surrounding the market since it opened.

Market Renewal is an attempt to right some of the well-known wrongs with Ontario’s electricity market. Yet, a number of changes proposed as part of the MRP are either being reduced or eliminated altogether. The updates included in MRP are necessary and long overdue if the province wants to move forward with a competitive and efficient electricity market. The IESO and stakeholders — both of which are vital components to any competitive market — now must decide whether they will support the current detailed designs regarding the most material aspects of MRP, or determine what the market should look like given the many unique aspects of Ontario’s grid.

*Brady Yauch is the manager of Markets and Regulatory Affairs at Power Advisory LLC. He has worked in the IESO’s compliance division and appeared many times before the Ontario Energy Board (OEB). He has been published extensively on matters related to electricity markets and regulation.

  1. Neil B. Freeman, The Politics of Power: Ontario Hydro and its Government, 1906-1995, (Toronto: University of Toronto Press, 1996) (HELCO’s was viewed simultaneously as a provincial corporation and a trustee of a municipal distribution co-ops).
  2. Hydro “sold” power to local distributors at cost.
  3. Dawna Petsche-Wark & Catherine Johnson, “Royal Commissions of Inquiry for the Provinces of Upper Canada, Canada and Ontario 1792 to 1991: A Checklist of Reports” (1992) at 64–65, online (pdf): Ontario Legislative Library <www.ontla.on.ca/library/repository/mon/27002/132991.pdf>; Ronald Daniels & Michael Trebilock, “Electricity Restructuring: The Ontario Experience” (2000) 33:2 Can Bus LJ 161; John Cruickshank, “Province to probe Ontario hydro costs”, The Globe and Mail (21 October 1983) 12 (Ontario Hydro’s debt in 1983 accounted for half of Ontario’s total outstanding debt).
  4. Lawrence Solomon, “Where should Ontario Hydro go from here?”, The Globe and Mail (19 August 1997) A21.
  5. Ontario Power Generation, “Lakeview GS 43 years of service to the Province of Ontario A pictorial retrospective of Lakeview Generating station” online (pdf ): Ontario Legislative Library <www.ontla.on.ca/library/repository/mon/16000/269120.pdf>.
  6. The final unit at Darlington didn’t come into service until 1993.
  7. Ontario Hydro, “Ontario Hydro Statistical Yearbook” (1992), online (pdf ): <archive.org/details/ontariohydrostat1992onta/page/6/mode/2up>.
  8. “Ontario Hydro loses $6.3-billion”, The Globe and Mail (18 February 1998) A1.
  9. The rate freeze was put back in place just months after the market opened.
  10. Anthony Depalma, “Canadians export a type of reactor they closed down”, The New York Times (3 December 1997), online: <www.nytimes.com/1997/12/03/world/canadians-export-a-type-of-reactor-they-closed-down.html>.
  11. Martin Mittelstaedt, “Change ‘unavoidable’ for Ontario Hydro, Lights Out: Giant utility’s woes mean a competitive market ‘is now inevitable”, The  Globe and Mail (18 August 1997) A1.
  12. Ontario Power Generation, “Annual Information Form for the Year Ended December 31, 2017” (9 March 2018), online (pdf): <www.opg.com/document/2017-annual-information-form-pdf>.
  13. Ontario Hydro ultimately built 4 nuclear units at Darlington. In 2006 it applied to build additional units at the site, but never moved ahead with the plan.
  14. Bertrand Marotte, “The crisis at Ontario Hydro is a…”, CanWest News (13 August 1997) 1.
  15. Office of the Auditor General of Ontario, “2013 Annual Report” (2013) at 318–20, online (pdf): <www.auditor.on.ca/en/content/annualreports/arreports/en13/2013ar_en_web.pdf>.
  16. The United Kingdom led the way with the privatization of its Central Electricity Generating Board (CEGB) in 1991.
  17. Marotte, supra note 14.
  18. Ontario Power Generation, “2000 third quarter report” (2000) at 7, online (pdf): <archive.opg.com/pdf_archive/Financial%20Reports/F129_OPGQ3.pdf>.
  19. Martin Mittelstaedt, “Brascon buys four Ontario hydro plants”, The  Globe and Mail (9 March 2002), online: <www.theglobeandmail.com/report-on-business/brascan-buys-four-ontario-hydro-plants/article18286993>.
  20. Ontario Power Generation, “2012 Annual Report” (2013), online (pdf ): <archive.opg.com/pdf_archive/Financial%20Reports/F035_2012AnnualReport.pdf>.
  21. Paris Fronimos, “ The Electrical industry in Ontario: Why Staying the Courts Matters” (16 March 2006), online (pdf): CABREE <www.ualberta.ca/business/centres/carmen/energy/~/media/5AA6406DBF434513A26C9AAA012BB805.ashx>.
  22. Andrea Baillie, “Ontario passes law to freeze electricity rates for four years”, Canadian Press (9 December 2002).
  23. Fred Grobet, Don McFetridge & Tom Rusnov, “Market Surveillance Panel Monitoring Report on the IMO-Administered Electricity Markets” (17 December 2003), online (pdf): OEB <www.oeb.ca/documents/msp/panel_mspreport_imoadministered_171203.pdf>.
  24. Michael J. Trebilcock & Roy Harb, “Electricity Restructuring in Ontario” (2005) 26:1 The Energy J 123; See “To pay the market price for Ontario’s electricity”, The Globe and Mail (19 August 2003), online: <www.theglobeandmail.com/opinion/to-pay-the-market-price-for-ontarios-electricity/article1334784/> (total cost was $1.5 billion, but was offset by rebates from OPG).
  25. Price spikes of $2,000 per MWh, which is the IESO-administered price cap, continue to occur in Ontario, but happen for a small number of five-minute intervals.
  26. Janet McFarland, “Electricity cheaper in Ontario: study”, The Globe and Mail (13 June 2002), online: <www.theglobeandmail.com/report-on-business/electricity-cheaper-in-ontario-study/article25298346>.
  27. Note that demand fell in the early 1990s as a result of a severe recession and the same time the Darlington nuclear plant entered service. Demand eventually picked up in the back half of the 1990s and continued to grow until 2005.
  28. As discussed later, many of the supply issues were known before market opening. What wasn’t expected was the sudden increase in demand that exacerbate that shortage.
  29. The Honourable Jake Epp, Peter Barnes & Robin Jeffrey, “Report of the Pickering “A” Review Panel” (December 2003), online (pdf): Ontario Legislative Assembly <collections.ola.org/mon/7000/10317476.pdf>; Roma Luciw, “OPG cancels Pickering repairs”, The Globe and Mail (12 August 2005), online: <www.theglobeandmail.com/report-on-business/opg-cancels-pickering-repairs/article1121297>.
  30. Trebilcock, supra note 24.
  31. By October 2002, as the weather cooled, demand dropped on its own accord and wholesale prices came down.
  32. “Market Surveillance Panel Monitoring Report on the IMO-Administered Electricity Markets” (24 March 2003), online (pdf): OEB <www.oeb.ca/documents/msp/panel_mspreport_imoadministered_240303.pdf>.
  33. Dina O’Meara, “Sithe puts off power project, blames capacity sales rules”,National Post (30 October 2002) FP12.
  34. Steve Erwin, “Price caps in Ontario electricity market risky, power producer warns”, Canadian Press (7 November 2002).
  35. Steve Erwin, “Energy industry sees little reason to build new supply after Eves’ price cap”, Canadian Press (11 November 2002).
  36. Ministry of Energy, News Release, “Ontario Government Introduces Fair And Stable Prices For Electricity From Ontario Power Generation” (23 February 2005), online: <news.ontario.ca/archive/en/2005/02/23/Ontario-Government-Introduces-Fair-And-Stable-Prices-For-Electricity-From-Ontari.html> [Fair and Stable Prices].
  37. John Spears, “Power shortage by ‘06, report says”, Toronto Star (25 January 2004) D01.
  38. Ontario Energy Board, “Monitoring Report on the IESO‐Administered Electricity Markets for the period from May 2005 – October 2005” (December 2005), online (pdf): <www.oeb.ca/documents/msp/msp_report%20final_131205.pdf>.
  39. Office of the Auditor General of Ontario, “2011 Annual Report” (2011) at 87–120, online (pdf): www.auditor.on.ca/en/content/annualreports/arreports/en11/303en11.pdf [Auditor General of Ontario, “2011”].
  40. Ministry of Energy, News Release, “McGuity Government Unveils Bold Plan To Clean Up Ontario’s Air” (15 June 2005), online: <news.ontario.ca/archive/en/2005/06/15/McGuinty-Government-Unveils-Bold-Plan-To-Clean-Up-Ontario039s-Air.html>; Micheal Wyman, “Power Failure: Addressing the Causes of Underinvestment, Inefficiency and Governance Problems in Ontario’s Electricity Sector” (May 2008), online (pdf): CD Howe Institute <www.cdhowe.org/sites/default/files/attachments/research_papers/mixed//commentary_261.pdf>.
  41. Jan Carr, “Making Ontario’s Electricity Market Work” (2005), online (pdf): <www.regie-energie.qc.ca/Camput/Presentations/MARDI-eng/Carr_presentation-eng.pdf>.
  42. Fair and Stable Prices, supra note 36.
  43. Ontario Legislative Assembly, Standing Committee on General Government, “Green Energy and Green Economy Act, 2009”, Official Report of Debates (Hansard), No G-21 (8 April 2009).
  44. Guy Holburn, Kerri Lui & Charles Morand, “Policy Risk and Private Investment in Ontario’s Wind Power Sector” (2010) 36:4 Can Pub Pol’y 465.
  45. The smart meter program, for example, was rolled out in 2004 and the OEB was blocked from reviewing it for cost effectiveness. The project was initially expected to cost $1 billion, but the Auditor General expects that figure to hit $2 billion.
  46. Richard Corley et al, “Ontario Feed-in Tariff Report Released” (2 April 2012), online: <www.mondaq.com/canada/Energy-and-Natural-Resources/170294/Ontario-Feed-in-Tariff-Report-Released>.
  47. Holburn, supra note 44; Auditor General of Ontario, “2011”, supra note 39.
  48. “A Progress Report on Contracted Electricity Supply: First Quarter 2019” (2019), online (pdf ): ieso <www.ieso.ca/-/media/Files/IESO/Document-Library/contracted-electricity-supply/Progress-Report-Contracted-Supply-Q4-2019.pdf?la=en>.
  49. Ibid.
  50. Environmental Commissioner of Ontario, “Making Connections Straight Talk About Electricity in Ontario 2018 Energy Convervation Progress Report, Volume One” (2018) at 94–109, online (pdf): Office of the Auditor General of Ontario <www.auditor.on.ca/en/content/reporttopics/envreports/env18/Making-Connections.pdf>.
  51. See “18-Month Outlook: An Assessment of the Reliability and Operability of the Ontario Electricity System from January 2007 to June 2008” (21 December 2006), online (pdf): ieso <ieso.ca/-/media/Files/IESO/Document-Library/planning-forecasts/18-Month-Outlook/18-Month-Outlook—2006dec.zip>; See also “18-Month Outlook: An Assessment of the Reliability and Operability of the Ontario Electricity System from October 2018 to March 2020” (25 October 2018), online (pdf): ieso <ieso.ca/-/media/Files/IESO/Document-Library/planning-forecasts/18-Mo nth-Outlook/18MonthOutlook_2018oct_v2.pdf>.
  52. Bill 135, An Act to amend several statutes and revoke several regulations in relation to energy conservation and long-term energy planning, 1st Sess, 41st Leg, Ontario, 2016 (assented to 9 June 2016), SO 2016, c 10.
  53. Bill 112, An Act to Amend the Energy Consumer Protection Act, 2010 and the Ontario Energy Board Act, 1998, 1st Sess, 41st Leg, Ontario, 2015 (assented to 3 December 2015), SO 2015, c 29.
  54. Adrian Morrow & Tom Cardoso, “Why does Ontario’s electricity cost so much? A reality check”, The Globe and Mail (7 January 2017), online: <www.theglobeandmail.com/news/national/why-does-electricity-cost-so-much-in-ontario/article33453270>.
  55. Ministry of Finance, News Release, “Helping Families Manage Electricity Costs McGuity Government Passes Ontario Clean Energy Benefit” (8 December 2010), online: <news.ontario.ca/mof/en/2010/12/helping-families-manage-electricity-costs.html>.
  56. See Ontario Power Authority, “EB-2007-0707, Exhibit D, Tab 1, Schedule 1 – Load Forecast – IPSP Reference Energy and Demand Forecast” (5 September 2008) at 1, online (pdf): OEB <www.rds.oeb.ca/HPECMWebDrawer/Record/81114/File/document>.
  57. See “2016 Conservation Results Report” (1 December 2018), online (pdf): ieso <www.ieso.ca/-/media/Files/IESO/Document-Library/conservation-reports/Annual/conservation-results-report-2016.pdf>.
  58. See Ontario Power Authority, “EB-2007-0707, Exhibit D, Tab 9, Schedule 1 – Meeting Resource Requirement” (5 September 2008) at 1735, online (pdf): <www.rds.oeb.ca/HPECMWebDrawer/Record/81114/File/document>.
  59. See Johannes Pfeifenberger et al, “The Future of Ontario’s Electricity Market – A Benefits Case Assessment of the Market Renewal Project”, (20 April 2017), online (pdf): ieso <www.ieso.ca/-/media/Files/IESO/Document-Library/engage/me/Benefits-Case-Assessment-Market-Renewal-Project-Clean-20170420.pdf>.

Leave a Reply