The restructuring of Ontario’s electricity system, which takes an important step with this month’s market opening, is part of a worldwide evolution. Just ten years ago, the world’s electricity systems were essen- tially run by large, regional, vertically integrated utilities, almost fully self-reliant, which provided generation, trans- mission and often distribution to captive customers. But now it’s possible to see quite clearly that we are in the mid- dle of a rapid evolution toward much larger, even continen- tal, open-market structures in which generators and cus- tomers can contract independently with each other wher- ever they may be. In the old world, prices were set by each vertically integrated utility as an approximation to its long- run average cost of service plus a mark-up, and these prices were regulated at the state or provincial level. Capital investment decisions were made by these providers in order to serve their own customer base. In this respect, Ontario’s system was not at all unique. It differed from the norm only in two major respects: First, the province itself owned the utility, Ontario Hydro (usually referred to as ”œHydro”). Second, distribution was largely in the hands of local Public utility commissions or municipal electric utilities (MEUs). These two circumstances reflected the way the system had evolved in the early decades of the 20th century. From the 1970s onward, a regulator was in place, but while the new Ontario Energy Board could require Hydro to explain and justify its generation and transmission rates in annual hear- ings, it was never given the power to disapprove those rates. In a very real sense, Hydro’s Board answered only to itself and to the premier, a reward for its long record of support to province-building.

Hydro was successful for decades in providing cheap and plentiful electricity, and in return, successive premiers were happy to let Hydro manage its own affairs. But Hydro blun- dered badly in the late 1980s. It ran into severe delays and cost overruns in building the massive new Darlington nuclear station, and then it got whacked with huge interest costs by financing Darlington just when John Crow’s Bank of Canada was pushing interest rates to their highs. Hydro got further blindsided in the early 1990s by the first significant decline in electricity demand in decades. All this forced it to raise prices by 30 per cent just as natural gas prices were collapsing" which naturally made its customers, especially its major industrial customers, angry. It became clear to Hydro man- agement that the excess capacity they had so expensively built could only find a sufficient mar- ket by looking south to the United States, where, coincidentally, the U.S. federal authorities had just mandated a new regime under which access to American transmission networks would be opened to all comers. This was the good news. The bad news was that in order to play, Ontario would have to provide access to its own wholesale cus- tomers on equal terms. In 1993, Hydro manage- ment floated a proposal that would do this, mak- ing use of an independent system operator that would manage access to the Ontario grid. To help restore financial integrity to the debt-heavy utility, Hydro management also proposed that the Crown corporation be merged with the debt-free munici- pal utilities, which would be compensated for the addition to their debt loads by giving them shares (but not control). Not surprisingly, this proposal was not palatable to the MEUs, so, to sort things out and buy some time, in 1996 Ontario’s new Tory government appointed Donald Macdonald, the former federal Liberal Energy and Finance Minister, to head an Advisory Committee on Electricity Competition. The committee agreed on the need to open Ontario’s market under an inde- pendent system operator. It also recommended that Hydro be restructured into successor compa- nies with strong balance sheets, and that the excess amount of debt over what they could feasi- bly carry be parked in a company created for the purpose. The committee proposed that Hydro’s excess debt should be gradually reduced by apply- ing interest and dividends from the other succes- sor companies and payments in lieu of taxes from the MEUs. In other words, the debt would be paid down out of ratepayers’ hides rather than taxpay- ers’, even though it carried a provincial govern- ment guarantee. The committee did suggest that the proceeds from any privatizations of the suc- cessor companies should also be applied to the stranded debt. But the real shocker for Hydro man- agement was the recommendation that its gener- ating facilities be dispersed and largely sold off to private owners in order to create a truly competi- tive market. The committee further recommended that electricity distributors"of which there were far too many, over 300"be kept out of Hydro’s hands and instead be encouraged to amalgamate into regional entities under a strong provincial regulator.

Facing resistance from both Hydro and the MEUs, the government delayed its response for over a year, but in 1997 revelations of nuclear mismanagement blew the lid off the file and a White Paper soon accepted many of the Macdonald Committee’s recommendations, including expanded powers for the Ontario Energy Board so that it could regulate both gas and electricity transmission and distribution. Crucially, Hydro was to be permitted to keep all its generation assets. One of the most ambitious commitments in the White Paper, however, was to simultaneously open Ontario’s wholesale and retail markets to competition. In the U.S., by con- trast, most utilities were beginning to open their wholesale markets up, under heavy pressure from the Federal Energy Regulatory Commission (FERC), but there was marked resistance to giving up their franchises at the retail level, and since this was an area of state jurisdiction FERC had lit- tle to say in the matter. Ontario’s over 300 municipal utilities were caught off-guard by the White Paper even more than Hydro was. Despite protests from many of them, however, the restructuring began.

A Market Design Committee (MDC) was estab- lished under Dean Ron Daniels of the University of Toronto Law School and given a year to come up with a market design patterned on the Macdonald lead. The MDC, like the Macdonald Committee, quickly realized that the market could not be competitive if Ontario Power Generation (OPG), the new name for Hydro’s generation business, was to start off with 85 per cent of the province’s generation capacity. So a deal was worked out, in consultation with Hydro and the government, under which OPG would gradually relinquish effective control of the pricing and operation of major facilities over the first ten years of the market’s existence, and at the end of that period would end up with no more than 35 per cent of the effective capacity serving Ontario. To provide more competition, the province also committed Hydro One"the distribution arm of the former Ontario Hydro" to a significant expansion of its inter-ties with other control areas such as Michigan and Quebec. OPG further agreed that until it had fully scaled back, it would rebate to Ontario cus- tomers any revenue representing more than 3.8 cents a kilowatt-hour, the price it was then in effect receiving on a large portion of the capacity it still controlled. Finally, the MDC recommend- ed that retail consumers should, as their standard option, receive a pure pass-through of the whole- sale spot price. Retailers would be free to offer alternatives, such as fixed-price contracts or green power; but the customer would always be able to compare those offers against the alterna- tive of staying with the distributor and receiving the spot price pass-through with no mark-up. One of my major regrets in the implementation to date is that retailers have been permitted to pre-market their fixed-price offers to consumers without having to inform them clearly about this alternative or about the OPG rebate they would be giving up. If the fixed-price offers turn out to be substantially higher than the spot price aver- age, many customers are likely to conclude that they have been hoodwinked.

In 1998, the government passed the Electricity Act and the Electricity Competition Act, and also established the five successor companies to Hydro: OPG, Hydro One, the Independent Electricity Market Operator (IMO), its Electrical Safety Authority and the Ontario Electricity Financial Corporation (OEFC). The latter has taken on the stranded debt and Hydro’s Power purchase contracts with the small non-utility generators. Since early 1999 the IMO, the OEB, and the rest of the industry have been laying the foundation for a competitive wholesale and retail market. For reasons that are hard to fathom, the province, having ambitiously decided to open the retail market at the same time as the whole- sale market, then largely left the MEUs and municipalities to get on with it on their own. Although the OEB quickly began to work out the elements of new regulatory requirements that would enable distributors and retailers to imple- ment the MDC recommendations, it had little ability to force action from the MEUs, many of which were unenthusiastic about the roles they were going to be expected to play. The munici- palities, now confirmed as owners of the MEUs but required to re-establish them on a commer- cial footing with commercial balance sheets, were generally more interested in financial questions, such as whether they should sell the new compa- nies or operate them on their own, and whether they should get into the more risky retailing busi- ness or stay in the essentially physical distribu- tion side.

Although there have been unforeseen delays in implementing the wholesale side of the mar- ket, it’s fair to say that implementation of the retail market was an even larger factor in delay- ing the market’s opening from late 2000 to May 1, 2002. To its credit, in the last 12 months the OEB has played a much more proactive role on the retail side, working out practical timelines and holding the distributors to schedule"even where necessary invoking the threat of penalties over them under the license provisions in the OEB Act.

During the last 12 months we have seen intensive testing of the IMO’s new software and hardware, first in-house and then through a series of tests involving selected market partici- pants. Preparations culminated in a run-in period during April in which the parties operated as if the wholesale market were open in every respect except the final exchange of dollars. Power was dispatched, generators ran (or not), and whole- sale settlement statements were issued"but the actual prices paid continued to be the old regu- lated price, until the IMO and OEB declared to the Minister that the markets could safely and reliably be opened, and the Minister declared them open. May 1 was chosen as the target open- ing date so that the monthly billing cycle would cut over smoothly. Some distributors and other wholesale participants were not entirely ready, and for them transitional arrangements were made.

As mentioned at the outset, opening Ontario’s market to competition is only one milestone on a longer journey. The long-term vision is that"making full and due allowance for reliabili- ty, safety and environmental concerns"electrici- ty is simply a commodity, and should take its place with natural gas and other fuels as an input to households and to enterprises and should be subjected to the innovative and productive forces of competition. As I mentioned earlier, this means moving from pricing based on long-run average cost, as projected and estimated by monopolists, to pricing based on short-run marginal cost, as determined by hungry competitors contending for the last megawatt of demand in a market that clears every five minutes. Competing generators are potentially infinite in number"though if that’s the case some will be very small"and their ability to match offers will be limited only by their own ingenuity and by the technical limitations of the transmission system.

In this context it’s important to point out that transmission is now potentially a competi- tive business as well. In fact, the transmission business is already changing. The new electricity markets across North America and elsewhere have begun to adopt locational pricing, where the price of energy can differ from place to place depending on the cost of delivering it. Congestion and line losses in the transmission system can create a situation where the generator who bids lowest is not necessarily the cheapest supplier to a given load. It may be necessary to use more expensive generation to meet certain loads, and the resulting price difference between one point and another provides an important signal for both potential new generators and potential new transmission providers. Either more generation can be built inside the bottle- neck or the bottleneck itself can be eliminated.

As this example suggests, it is not really appropriate to open generation to competitive forces without doing the same for transmission, so long they can be treated in a fair and compa- rable manner. The key issue that remains unsolved at present is just how to integrate trans- mission investment and generation investment in a common scheme. Whereas generation investment tends to affect only the conditions in its immediate vicinity, transmission investment can have far-reaching effects on the efficiency of an entire network, not just a small region. Finding the right mechanism for apportioning costs and benefits has not turned out to be easy. On the other hand, even the so-called free com- petition that we are trying to establish in genera- tion is turning out to require a very elaborate structure of market rules to sustain it. I think we need to get to a stage where transmission propos- als have a fair shake against each other, as well as against competing generation proposals, but it looks as if there may have to be a fair amount of regulatory overhead involved if competition is to be effective. In any case, allowing energy prices to vary by location will be an important compo- nent of the final structure of an effectively func- tioning market. We will be opening the market with a single province-wide price; but the MDC recommended that locational marginal energy pricing (LMP) be investigated within 18 months of market opening, and the IMO Board intends to do that.

This is a very good time to be opening elec- tricity supply up to market forces. In recent years, innovation has been as profound in the energy industries as it has been everywhere else. As far as generation is concerned, there have been dramatic cost reductions in wind and solar power. There has been rapid development of micro-generators based on turbines that use a variety of fuels, including natural gas, and are sited right where the demand is. New and antici- pated environmental policy constraints on fossil- fuel emissions have made for furious innovation in ways of reducing the ratio of emissions to megawatts. On the transmission front, new lines can be built on old rights-of-way using supercon- ducting media, thus vastly increasing capacity without requiring lengthy environmental assess- ments. And there are new possibilities of using large-scale storage media to permit shifting of supply from non-peak to peak periods. On the distribution front, XML-based billing and settle- ment software is making it easy and cheap for customers to transfer their business from one retailer to another and for retailers to construct interesting cross-marketing deals with gas and other products. And the distributors themselves are quickly being amalgamated into large-scale regional super-entities that will be capable of delivering multiple commodities such as electric- ity, gas, water and data.

Once the market has found its legs, these aspects of the business will have to be just as innovative as the others. Indeed, as the new mar- ket begins, the Ontario Energy Board is laying the foundation for a new performance-based regula- tory regime for transmitters and distributors. As is well-known, performance-based regulation (PBR) only works well if it mimics the rigours of competition, even though in the end it does spare the subject firms from many of the vicissi- tudes of the real competitive world. It’s my hope that the Ontario Energy Board will be tough- minded in applying PBR and will force the dis- tributors to reach as high for the fruits of inno- vation as genuine competition will require the rest of the industry to do.

One of the key problems in establishing the new market for electricity is getting the price signals through to customers in a usable form. In the wholesale market, we will be provid- ing such signals to domestic generators every five minutes, but the prices charged to customers will be hourly averages of these five-minute prices. As the MDC recommended, those hourly wholesale spot prices will be passed through to all cus- tomers, large and small alike, without a mark-up by the distributors. But unless the customer has an interval meter, the price she pays will be aver- aged over her billing period, based on a load pro- file for each local distributor. Prices are expected to vary substantially over each day, and there is also likely to be meaningful variation across the days of the week, from one season to the next, and when weather or unexpected equipment outages place unusual stress on the system’s resources. To the extent that customers can arrange their affairs to respond to changes in the price, they may be able to reduce their bills sig- nificantly"but that is only possible if they have an interval meter, so that their load can be sub- tracted out and billed separately.

As mentioned above, we can expect signifi- cant price volatility in this new market. The demand for electricity varies dramatically by the hour of the day, by the day of the week and by the season of the year. The supply curve that faces that demand can be quite steep over at least part of the relevant range, especially when equip- ment outages or weather conditions place limita- tions on what can safely be delivered. When a volatile demand curve meets a steep supply curve, prices can fluctuate sharply.

When prices are based on the short-run mar- ginal cost of the marginal supplier, there can be no assurance that all or even most generators will cover their fixed costs in every hour. Given the anticipated swings in demand, it is very possible that certain suppliers will only be called upon for a relatively small number of hours in the year. In order to stay in business, they will have to be able to count on prices that are high enough during those hours to allow them to cover their fixed costs and provide an acceptable rate of return on their investment. If all the province’s nuclear units come back on line, Ontario is going to have a lot of baseload capacity, so prices may not reach those heights very often. If prices stay relatively low for long periods, these ”œpeaking plants” could be driven out of business, and the supply curve could start to look like a very steep ”œJ”. Over the years, as demand grows, the point where the demand and supply curves cross could start climbing up the ”œJ” very quickly. Prices could then rise very high for lots of hours in the year, at least until new generation can be built. We could end up with a cobweb cycle, where prices would be very low for some years, then very high, and so on.

How can customers be protected against this prospect? Should the IMO Board take steps to mitigate the problem and, if so, what should those steps be? One obvious strategy is with inter-ties to other jurisdictions such as Quebec, Manitoba and the United States. A key way to encourage inter-jurisdictional trading will be to have ”œpostage-stamp pricing” of transmission: an energy trader who pays for access to his own sys- tem is granted free access to all the others. Since the actual energy flow does not impose costs on the grid, this would be quite feasible. But Ontario and its neighbouring jurisdictions will have to negotiate how do to this, and we are not there yet. (By the way, it’s important not to confuse grid usage charges with congestion charges. The new systems that are developing will, as men- tioned, include congestion charges as a key ele- ment in locational energy pricing. But paying when you cause congestion is not the same as paying for access.)

Another of the possible responses the IMO Board could make to this concern about high peak prices is to establish a ”œcapacity market.” If we had deep financial derivatives markets where forward price curves could act as a pooling of information on likely trends, that in itself would reduce the likelihood of cobweb cycles. But we don’t yet have such markets. In the meantime, it has been suggested that the IMO should contract for extra reserves, that is, should set up a market in which it would solicit offers from generators to stand idle but available, 24 hours a day, so that when peak loads come there will be capacity to serve them. As it stands, the Ontario market is going to start out with a market in ”œoperating reserves,” that is, generation that is ”œwarm” and can be used within ten minutes or 30 minutes of being called upon. In this respect, we are essen- tially observing the reliability requirements established by the industry many years ago. But at an early date the IMO Board will be exploring whether to go further and put a price on even more capacity"that is, to pay generators to hold even more excess in reserve that could be revved up on, for example, a day’s notice. The IMO would bear the cost and pass it on to consumers in its general administrative charges. The result, presumably, would be fewer price spikes, and energy prices that would be less volatile over time. We will, I think, want to observe the mar- ketplace carefully for some time before making a decision on this matter.

As economists know well, solving one prob- lem can lead to another. If we want to keep marginal or peaking plants in business, we may have to either put consumers to the expense of sustaining capacity markets, or tolerate very high prices for some hours of the year. But, as I have mentioned, strong linkages with Ontario’s neigh- bours may alleviate this concern. And there is another way that the market will respond. Because OPG has until now quoted the same price in every hour, most customers have not experi- enced variable prices. But in the new market, spot prices will vary over the day, across the week, and from season to season. Large customers, who will have interval meters that measure their usage from moment to moment, may turn out"at least some of them"to have quite a price-elastic demand. For example, technology has been advancing very quickly in the area of distributed generation"e.g., the small gas-fired turbines I mentioned earlier, which a shopping centre or small manufacturing company could turn on at peak hours. There is also interesting work going on in energy storage that could allow customers to take energy at cheap hours and use it at peaks. I suppose we shouldn’t expect miracles in the first year or two, but we should be prepared to see quite remarkable and innovative demand-side responses to the new price volatility.

In the meantime, even though Ontario’s market has been designed to pass through the wholesale market price directly to small as well as larger consumers with no mark-up, it is far from irrational for users of electricity to explore fixed- price contracts with retailers. Such hedging activ- ity can only prove beneficial, however, if cus- tomers have good information about the alterna- tives. Until very recently the small consumer has not had that information, and as a result an unfortunate situation has developed. Speaking personally, this is the most serious blot on what I consider to have been an extraordinarily well- managed restructuring process.

Concern about price volatility raises the question of derivative markets. There’s no ques- tion that forward price curves and futures con- tracts in electricity would be useful. But who will provide them? Should the IMO simply concen- trate on providing good clean spot prices or should it consider adding derivatives to its product mix? Maybe it should get into the business of value-added information products. This question of how far to support or even undertake the development of financial markets to complement the physical spot market that we will operate in Ontario is a key challenge for the IMO. Looking ahead to a continent-wide marketplace, the IMO may not have a comparative advantage in this area. At the very least, however, it does intend to do one thing well, and that is to operate an open, fair, rules-driven, spot market in physical energy created or delivered in Ontario.

An innovation in the design of the Ontario market is its treatment of green power. Although many environmentalist groups lobbied hard at the MDC for preferential treatment of energy from renewable or green sources, their position was on the whole rejected. In the new market design, any retailer can procure energy from green producers, and will be able to sell it to consumers on a contract basis at whatever premi- um he can get. All energy bills, without excep- tion, whether from distributors or from retailers, will have to indicate specifically what mix of gen- eration has been used. For its part, the IMO will keep track of what has been generated by whom, so as to provide an audit database against which retailers’ claims can be evaluated.

The MDC heard strong representations from environmental lobbies that renewable or green electricity should get preferential treatment, for example by enforcing a ”œrenewable portfolio standard” whereby some percentage of total Ontario requirements would have to come from renewable sources. The MDC rejected these requests, however, on the grounds that the mar- ket should be as level a playing field as possible. If government wishes to provide such subsidies as a matter of public policy, then there are other ways of doing so. The MDC did propose that small generators, whether green or not, should be allowed to contract with their local distribu- tors to sell power on a self-scheduled basis at the prevailing spot price. Only if they were larger than a threshold size would they be required to go through the trouble and expense of register- ing and being licensed as a wholesale market participant.

Does an open electricity marketplace, popu- lated by many firms with assets and cus- tomers on both sides of the border, hold worri- some implications for Canadian sovereignty? Canadian regulators have long accepted, as have American ones, that reliability is a paramount issue of public policy; but NERC, the National Electricity Reliability Council, has been operated by the incumbent U.S. and Canadian utilities as a self-policing body for many decades and govern- ments have on the whole kept out of the way. NERC rules were designed for mutual assistance between utilities that were largely self-sufficient, and the inter-ties between them were generally not much larger than was necessary to facilitate such assistance. In the U.S., where open access is the rule, marketers have started trying to move major amounts of energy from one system to another. In many cases this has caused serious physical congestion on the wires"and apoplexy in utility boardrooms. The utilities no longer treat each other with gentlemanly deference, and they have sometimes found it difficult, occasion- ally impossible, to agree on new rules. NERC, in exasperation, mandated last year that the utilities must delegate the operational control of their grids to new large-scale entities called Regional Transmission Organizations (RTOs) and many people in the industry are concerned that NERC may take over the reliability regime as well. In Canada, the federal government has jurisdiction over international electricity trade through the National Energy Board, but in practice the provinces, through their utilities (which are members of NERC), have effectively managed the cross-border trading that has taken place.

Some observers are concerned that if we do open up the border, Canada will lose its capacity to regulate its own markets and will simply have to accept whatever rules the Americans work out for themselves. Others will feel that Ontario should retreat into itself and continue to rely on its own resources. My view is that it’s unnecessary to settle for the first option and too late to choose the second. The governments of Brian Mulroney and Jean Chrétien have delivered us, irrevocably, into a situation where almost 40 per cent of Canada’s GDP is destined for U.S. customers, while a third of all we buy is made south of the border. We don’t expect our supermarkets to be limited to Ontario tomatoes, nor our car dealers to Ontario-built cars. Why should we expect Ontario to continue on as an electrical island? We should recognize that Ontario and its neighbours can all win from being more closely linked, through commercial transactions, than ever before. As I mentioned earlier, being part of a 150- megawatt marketplace instead of a 25-megawatt marketplace could improve reliability immensely, smooth out price spikes and keep pencils sharp right across the industry. We shouldn’t try to cut electricity out of this continental reality; but we should vigorously ensure that our own interests and our own regulatory standards are upheld. The IMO Board doesn’t answer to American regula- tors, it answers to the Ontario Energy Board. Competition policy in Canada is set by the feder- al Competition Bureau. We should certainly facil- itate seamless cross-border electricity trading, but not at the expense of our own preferences.

Finally, privatization. As the Macdonald Committee advised the government in 1996, once proper market rules have been estab- lished and a proper regulatory structure has been put in place to assure reliability, safety and environmental protection, there will no longer be any good economic reason to keep electricity assets in government hands. Macdonald did propose keeping the nuclear fleet in public hands because of concern about risk issues, and he proposed to keep the Niagara River hydro generation public for admittedly sentimental reasons. But OPG will soon have a much small- er footprint in Ontario than it does now. Both OPG and Hydro One clearly have ambitions well beyond the province. They see themselves as players in a larger North American market- place, just as the Canadian banks and railways do, and this makes good sense to me. So far gov- ernments have not placed any major obstacles in their way"nothing at least compared to CN’s difficulties in acquiring Burlington Northern, or the restrictions placed on bank mergers. Under the circumstances, I think good public policy means selling these companies to private investors, using the proceeds to reduce the remaining stranded Hydro debt, and opening the Ontario electricity system to all who qualify under our market rules, in order to make it as efficient and reliable a component of the emerg- ing continent-wide markets as it can be. As this article went to press, Hydro One’s impending privatization was halted by court action; but I would be surprised if that event led to more than a relatively brief delay.

 

These remarks, originally presented in slight- ly different form at a meeting of the Toronto Association of Business Economists, February 20, 2002, are solely his own and should not be attrib- uted to the IMO.