INDUSTRY RESTRUCTURING

California Shorts a Circuit:
Should Canadians Trust The Wiring Diagram?

California's crisis in 2000-01 shook the worldwide electricity reform movement, intensifying debate on the merits of competitive generation markets.

Competition advocates argue that design errors by California's reformers caused the crisis. One mishap, in contrast with reform successes elsewhere, does not justify forgoing the consumer benefits from improving operating efficiency and sharing investment risk with private producers. Smaller, competing electricity suppliers are the future, replacing monopolies that never understood the full risks inherent in megaprojects such as nuclear plants.

According to skeptics, however, California's experience proves that electricity's unique characteristics thwart competition, so efforts at market restructuring will ultimately hurt consumers. Electricity is essential to modern economies, and it cannot be stored; demand and supply must always be precisely equal everywhere on the grid. These special conditions mean that the cyclical pattern of commodity markets will be exaggerated in the electricity sector, leading to California-like extremes of supply shortages, skyrocketing prices, profiteering, and costly blackouts.

What is the lesson from California? Should Canadian jurisdictions abandon the reform trend, even reversing it in Alberta and Ontario?

The answer is no. Competitive electricity markets are achievable, and the potential social benefit is enormous given the risks facing electricity investments today.

California's calamity shows, however, the large risks from market design mistakes. Reformers must create incentives to ensure that the market has an adequate capacity reserve and that some consumers will quickly reduce their demand when markets tighten. The system operator should have effective means to acquire supplies on short notice. Long-term supply contracts should protect most of the consumer bill from short-run price fluctuations.

The reform movement should continue. But reforming jurisdictions need to be more cautious and more cognizant of electricity's uniqueness when designing competitive markets.

Cautions for Reformers
The fact that California's prices have subsided does little, however, to ease concerns of those in other jurisdictions who are contemplating electricity market reform. The state's electricity bill during the one-year crisis was enormous and has not yet been recovered from consumers, taxpayers, and perhaps suppliers (some of whose profits are under FERC investigation). New long-term contracts signed in haste by the state government may saddle future consumers and taxpayers with an additional unnecessary liability of several billion dollars if the agreements turn out to be above market value. Retail prices are now much higher than when the restructuring process began in 1996 and have little prospect for decline in the coming years. What assurance is there that this situation would not happen elsewhere?

To put the point another way, California has, at great cost to itself, provided other jurisdictions with a free demonstration of the risks of electricity reform. It now appears that the probability of something going wrong is greater than many reformers assumed. And the losses that result can be dramatic. Recent studies show that the losses from power outages in the United States prior to California's forced rolling blackout were already in the tens of billions (EPRI 2001).

What can we learn from this experience? To this end, three questions are important:

1. Why was there insufficient investment in new capacity in California during the 1990s such that tight market conditions developed?
2. Given the requirement to balance supply and demand instantaneously at all points on the electricity grid, how difficult will it be to prevent the exercise of market power during tight conditions in electricity markets?
3. Given the essential service character of electricity for most customers, what is the potential for demand response to help reduce spot market price volatility?

I find myself between these two positions. I agree that the potential social benefits of competitive electricity markets are great and should be pursued in any jurisdiction.

The alternative of leaving major investment decisions to central planners, with the costs of mistakes borne by all, is not a good way to address pervasive investment risk in the electricity sector. Moreover, improving the efficiency of electricity systems offers substantial benefits and competitive markets provide the incentives for realizing them, as we have already witnessed through the development of interjurisdictional trade at the wholesale level. At the same time, I believe that the unique characteristics of electricity as a commodity are so significant that the designers of markets for it must be much more cautious than they have been. They must be much more willing to incur extra costs in system design and operation in order to ensure that supply investment sustains the capacity reserve margins needed for most customers' high standards of reliability and price stability. In contrast, California's reformers were at best remiss and at worst arrogant in this regard, and several other reformed and reforming jurisdictions -- sometimes sounding quite smug when discussing California's misfortune -- may be equally at risk.

Problems can occur if electricity reforms are designed by market enthusiasts who believe that everyone is, or should be, as excited as they are about the intricacies of competitive markets. In the real world, industry and large commercial customers may be interested, but almost all householders simply want to pay a stable, manageable rate for a reliable supply that they never have to think about, even if that security costs a reasonable premium. This characteristic of electricity puts the onus on market reformers to include mechanisms that ensure a highly reliable service to almost all consumers. Thus, cautious market reformers should reduce the likelihood of extreme supply and demand imbalances by including an extra incentive, at a reasonable cost, that compensates risk-taking investors for the chance that their units may run infrequently during times of excess supply. Pricing and contracting mechanisms can also ensure average retail price stability during times of volatile wholesale spot markets, without creating a financial imbalance. Providing opportunities and rewards for those consumers -- usually, but not exclusively industrial customers -- who can and are willing to reduce demand in response to price signals would further improve the prospects for a stable market.

What happened was certainly not what the system designers expected. Investment did not occur when needed, and the market tightened with no potential for short-run supply response. Wholesale prices skyrocketed well above the marginal costs of production, suggesting substantial profit taking. Moreover, retail demand did not respond to ease the situation -- a not-unexpected result, given that retail prices were not allowed to change. I now examine each of my earlier questions in turn.

Reform Experiences in Canada
The importance of provincially owned hydro power resources explains in part why electricity market reform has been slower in Canada than in the United States. Another key factor is that most Canadian jurisdictions have fairly low electricity prices. They are a legacy of the country's hydro power endowment and low-cost coal deposits and of provincially owned utilities that have very low costs of capital because of high debt-to-equity ratios with the cost of borrowing lowered by provincial securitization and because of their exemption from federal income tax. Two Canadian provinces have pursued electricity market reform for ideological and cost reasons. Alberta has a conservative tradition of minimizing the role of central planners and favoring markets and private ownership where possible; before the 1990s, it was the only province dominated by privately owned utilities. Indeed, Alberta stands out as a region interested in electricity market reform despite having some of the lowest electricity costs in North America. In contrast, Ontario's electricity sector reform had been motivated primarily by high costs, although ideology also played a role. From the time its Progressive Conservative government reached power in 1995, it has sought to reform the electric sector in order to reduce government involvement and lower prices through competition.

Alberta
Alberta's reform, like California's, started relatively smoothly, but then it too entered a challenging phase, albeit not one approaching the crisis proportions of California's. Before the reforms, the province's electricity sector was dominated by three vertically integrated utilities, two of them investor-owned (TransAlta and Alberta Power) and one municipally owned (Edmonton Power). Vertical deintegration proved a fairly easy step because of the earlier creation of a power-pooling mechanism. In 1982, to ensure uniform wholesale rates throughout the province, the Alberta government had established an agency to purchase electricity from all generating units at regulated, cost-of-service rates and then resell it to the distribution arms of the utilities at an averaged, uniform rate.

In its Electric Utilities Act of 1995, the Alberta government required the utilities to relinquish control of their transmission facilities to an independent transmission administrator (much like an ISO) and created a mandatory Power Pool that began operation in 1996 (Alberta Resource Development 2000). To preserve the benefit of low-cost generation for domestic customers, the government legislated long-term, fixed-price contracts between the separate generation and distribution divisions of the utilities. These agreements allowed average retail prices to remain at stable, low levels regardless of the Power Pool price. The latter functioned as a typical spot market, determining the trading price and dispatch merit order for wholesale market balancing in the short term, while providing signals of market tightening for long-term supply investment decisions.

The Alberta government implemented further market reform in 2000 by forcing the utilities to divest themselves of the production rights from their generation assets. The method used was an auction of power purchase agreements, which specified fixed monthly payments from the new owners of the generation rights to the owners of the assets (to cover marginal generation costs and unrecovered capital costs). Now, the owners of the generation rights must bid all of their power into the Power Pool but can sign long-term hedging contracts with customers.

The designers of the reform had assumed that the auction would generate a large surplus representing the difference, over the economic lives of the generating plants, between their low cost of production and rising Power Pool prices as the market tightened. Instead, the auction in mid-2000 attracted few bidders, and the bid prices were far below government expectations; the total revenue of the initial auction was just over $1 billion.

The timing could not have been worse. In the year before the auction, the average Power Pool price was less than 5 cents per kWh, and it had been even lower in 1998. But in summer 2000, the average wholesale price rose quickly to 20 cents per kWh and remained in this range to the end of the year. A crude analysis shows that, at prices above 8 cents per kWh, most purchasers of generation rights would see their initial investment paid off within a year. Thus, these investors could earn substantial profits for the remaining life of the power purchase agreements, some of which last for close to 20 years. This money would have remained with consumers had the long-term contracts not been replaced with the auctioned power purchase agreements.

Several factors contributed to the sudden rise in the Power Pool price in the period immediately after the auction. First, because natural gas units are the marginal producers in Alberta, the Power Pool price was influenced by the rising natural gas price throughout North America, which was especially pronounced in the western regions affected by California's increased natural gas demand. Second, although Alberta is not directly connected to the United States, its 400 MW link to British Columbia provides an opportunity for BC Hydro to purchase power from Alberta -- bidding up prices if necessary -- in order to sell it into the lucrative regional market in and around California. Third, analysts have raised questions about whether the Alberta spot price, like that in California, may have been increased by the bidding strategies of influential suppliers.

On the demand side of the market, the initial plans were for all customers to receive retail access in January 2001. As prices skyrocketed, however, Alberta put these plans on hold and capped retail rates. Unlike California, it has been able to do this without creating a financial crisis because the rate cap is tied to the results of a second auction that sold the generating rights (only for 2001-03) to plants not covered in the first auction, with the requirement that power be supplied at the wholesale price of 11 cents per kWh. The combined revenues of the two auctions totaled $2 billion, which the government rebates monthly to customers at 4 cents per kWh. Within two years, the auction revenues should be exhausted. When distribution and other costs are added to the wholesale price and the rebate, Alberta's net residential rates for 2001 were about 12 cents per kWh, giving the province the dubious distinction of jumping from one of the lowest to the highest electricity rates in the country.

Where do all these events leave Alberta today? It has still not achieved the competitive market that planners envisioned. Rather, it has significant market intervention by regulators and government. But the government remains hopeful that significant expansion plans for generation capacity will, within a few years, create enough competition and an adequate reserve margin to drive retail prices back down to the stable, low levels that were anticipated in 1998.

Other Canadian Jurisdictions
Most other Canadian jurisdictions have opened their transmission networks to third-party access; the usual motive has been simply to meet the minimal reciprocity requirements of the FERC for transmitting electricity through other jurisdictions in order to reach US markets. Independent power producers find few domestic opportunities when the vertically integrated monopoly is virtually the only potential purchaser of electricity.

Other than Alberta and Ontario, Quebec has gone furthest toward a competitive generation market. Although Hydro-Québec is not fully vertically deintegrated, the company is divided into distinct generation, transmission, and distribution divisions and a law in June 2000 (Bill 116) established a competitive relationship between the company's generation division and independent power producers. The law fixes a quantity and price (165 TWh per year at 2.79 cents per kWh) for Hydro-Québec's existing hydro power resources as a continuous supply obligation from the generation division to the distribution division of the company, thereby providing domestic customers with an indefinite entitlement to the province's low-cost hydro power resources. For supplies to meet load growth, the generation division must now compete with independent power producers in placing supply offers before the distribution division. The latter uses an integrated resource planning process, under the regulation of the independent utilities commission, in determining its resource portfolio for new supply. This industry structure is generally referred to as wholesale competition, although purists would argue that true wholesale competition exists only when the distribution utility severs all corporate links to the owners of generation units.

Other Canadian jurisdictions are in a wait-and-see mode. New Brunswick and Nova Scotia are perhaps the closest to taking reform action of some sort. Each has a Progressive Conservative government that is looking for ways to diversify the current monopoly situation without yet embracing full market restructuring.

Suggestions for Canadian Reformers
The recent difficulties of California and, closer to home, Alberta send a clear warning about the perils of electricity market reform, especially about the assumption that electricity can be treated identically to other commodities. Should reform therefore be abandoned? Should Canadian jurisdictions simply retain their publicly and privately owned monopolies on a business-as-usual path?

The answer is no. The risks of the monopoly model are great, though not always obvious at the time investment decisions are made. The electricity sector today is as uncertain as ever, and big misinvestments will occur. The monopoly model saddles all customers (or taxpayers) with these risks, instead of allowing private investors to play a risk-taking role. Ontario Hydro's experience with nuclear power is a clear illustration of this limitation of the monopoly model. Also, competitive markets improve operating efficiency. The expansion of wholesale electricity trading throughout North America over the past decade has shown the enormous efficiency gains that competition can bring.

Blind faith in markets is, however, just as dangerous as blind faith in central planning. Any reform design that seeks benefits from the long-run cost efficiencies of competition must address the special characteristics of electricity. These characteristics bring large financial risks, as California has so emphatically demonstrated. Because electricity supply and demand must be kept in physical balance at all times and because electricity is so essential to modern society, a competitive market is especially vulnerable to an exaggeration of the price and investment oscillations that are common to all commodity markets. These possibilities, in turn, enhance the potential for suppliers to detect and exploit temporary conditions of market power, which can further accentuate market volatility. In the face of this challenge, what are my specific suggestions for Canadian reformers? I begin by summarizing my answers to the three questions about California's calamity.

1. Until we have a great deal of experience to the contrary, we should assume that, in the absence of specific mechanisms, competitive electricity markets will experience a cyclical pattern of overinvestment and underinvestment, with the latter leading to periods of inadequate reserve margins and diminished reliability.
2. We should assume that, in tight market conditions, suppliers will be able to influence the spot market price.
3. We should incorporate mechanisms that enable demand-side response that can cost-effectively dampen spot market price volatility while recognizing that any mechanism will be insufficient to eliminate all such volatility.

• to limit the potential for extreme price volatility and price manipulation in spot markets, including any associated reduction in system reliability; and
• to reduce the influence of short-run market price volatility on average retail rates, while ensuring that price signals are transmitted to consumers who can respond in ways that improve system efficiency.

But the designers of market reform must understand that the risks on the other side can also be very large if substantial precautions are not taken. That is California's lesson.

Mark Jaccard is Associate Professor in the School of Resource and Environmental Management at Simon Fraser University, where he heads the Energy and Materials Research Group. This article is extracted from a recent C.D. Howe Institute Commentary written by Mr. Jaccard. ET