Power Projects & Power Purchase Contracts: Uncertainty Rules


The central premise of economic deregulation is that retail and corporate consumers are better served through open marketplaces than through regulated monopolies or oligopolies. The objective is to tear down the legal walls that prevent entrepreneurs, large and small, from offering a potentially cheaper, more innovative, more convenient, more responsive, or just plain more attractive alternative to the one-size, one-price, our way vs. the highway approach to supplying goods and services. Then all one has to do is sit back and watch creativity surge, investment climb and prices drop. At least this is what we are told.

The long distance telephone service industry is a spectacular example of how well market theory can work in practice. Today, friends in St. John's and Toronto can talk around the clock for an entire month and pay less than a five-minute call would have cost them twenty years ago (in constant dollars)! Everyone agrees that this is the end result of market competition.

Will a similar result be achieved as a result of the restructuring of Ontario's electricity industry? In the long term one has to bet on market competition. But in the short term, especially during a period of transition from monopoly to marketplace, anything can happen, particularly in such a unique and complex industry as electricity. This uncertainty makes investors cautious. And uncertainty, generally speaking, is good for the legal profession.


Power Projects "Uncertainty" best describes the state of mind of Ontario's electricity industry. It was cited as a dominating variable in the energy practice of every lawyer interviewed for this series of articles, particularly those who specialize in the financing, construction or acquisition of power generation facilities. A clear consensus exists that there is, as of yet, no gold rush. Even though the gates to a $10 billion dollar a year industry will be thrown open this November, investors and developers are so far talking but not walking, let alone running. More than two billion dollars worth of new power projects have been announced for Ontario since the Energy Competition Act (Bill 35) was enacted in late 1998, but the amount of sod actually turned since then wouldn't fill one of Tiger Woods' divots.

The main reason for the uncertainty can be answered with one word: OPG. What's happening with Ontario Power Generation (OPG), which currently controls approximately 85 per cent of all electricity production facilities in the province? What is supposed to happen is OPG's divestiture, within ten years of market opening, of all but 35 per cent of generation capacity available to the province. A large chunk of that divestiture must be complete within four years. This downsizing was the main feature of the 1998 Market Power Mitigation Agreement (MPMA) negotiated by OPG's predecessor, Ontario Hydro, with the Market Design Committee, a high-level power industry committee appointed by the government to advise on the framework for Ontario's electricity marketplace. But despite the MPMA, which was intended to give investors the assurance that Ontario would indeed be a vigorously competitive power marketplace, there has been a decided reluctance to commit to the actual building of new generation capacity in the province, primarily because the scope, timing and results of OPG's divestiture are still unknown, even to OPG itself.

"Are you assuming there's a market just because there have been several major new cogeneration projects announced in the past year?" asks Donald G. Gibson. Gibson heads the Power and Energy Services Group at the Toronto office of McCarthy Tétrault, a firm that includes the Hon. Donald S. Macdonald, former Federal Minister of Energy and Chairman of the blue ribbon Advisory Committee on Competition in Ontario's Electricity System, and Richard Drouin, Q.C., former Chairman & CEO of Hydro-Québec. The McCarthy Tétrault Power Group has worked on scores of power projects throughout North America and is currently active in several international projects. They also advise an alliance of municipal electric utilities north of the city of Toronto, known as the Upper Canada Energy Alliance, which has put in place group purchases of electricity and other energy services. Like most lawyers with electricity portfolios today, Gibson has considerable experience in the natural gas industry which began deregulating in 1985. One of his posts prior to joining McCarthys was General Counsel and Secretary for the Canadian Arctic Gas Project.

"Generation capacity in Ontario still exceeds the demand," Gibson says. "Peak summer demand is around 22,000 megawatts and the median peak daily demand is 16-17,000 or so. Ontario's generation has been estimated to exceed 30,000 megawatts of installed capacity. Ron Osborne (OPG President and CEO) says they're going to divest 4,000 megawatts of fossil and hydroelectric generation in the next short while, but I think the Lakeview and Lennox (fossil-fueled) plants are a major portion of that and both of those, I suspect, may have environmental emissions considerations."

Converting a coal station to burn natural gas is expensive and with the price of gas going up more than 50 per cent in the last year, the economics of such projects are dimmer than ever, particularly in the Ontario marketplace with its massive nuclear capacity. If all of the province's twenty nuclear units were operating at design capacity, they could supply more than 14,000 megawatts at a marginal cost well under that of gas generation. It is true that the dismal performance of Ontario Hydro Nuclear over several years led to the lay-up of 40 per cent of its capacity so that the remaining twelve units could be operationally upgraded. But although this turned Ontario into a net electricity importer, the eight non-operating units could come back to haunt anyone who invests money now to try and displace those imports. Pickering A's four laid-up units (about 2,000 megawatts) will be restarted by OPG if the station passes its required environmental assessment and Bruce A's four idle units are up for sale, along with Bruce B's four active units. Not lost on anyone is the fact that the giant UK-based British Energy is currently negotiating with the Ontario government for the entire Bruce site, which produces about 6,000 megawatts.

Brian Dominique of Cassels Brock & Blackwell LLP lists the uncertain state of nuclear as one of his clients' list of reasons for taking a "wait and see" approach to the Ontario marketplace. Dominique is a corporate commercial lawyer who has worked on numerous generation projects during the last eight of his eleven years in practice. His firm was retained by the Ministry of Energy in early 1998 to advise on the "nuts and bolts" of Bill 35 and the restructuring of Ontario Hydro as well as by the Ministry of Finance and the Ontario Financing Authority to advise on certain legal matters relating to the financial aspects of the restructuring. Cassels Brock assisted with the legal work on the break up of Ontario Hydro into its successor companies and the transfer to them of Hydro's billions of dollars of assets and liabilities. "We started in mid-December 1998 and wound up about five minutes to noon on March 31, 1999 (when Ontario Hydro was sunset). The team of lawyers involved people at our firm, at the Ministries of Energy and Finance, at the Ontario Financing Authority and at Ontario Hydro. We literally ran the orders-in-council into the Cabinet Office." The firm acts for several private interests in the electricity industry and still acts for the Ontario Ministries of Energy and Finance and remains involved in a wide range of issues, including advising the government on the management of the assets and liabilities of successors to Ontario Hydro.

Dominique has a clear grasp of the almost Rubik's Cube-like alignment of variables which must take place before the uncertainty, and in some cases bewilderment, which characterizes the viability of new power projects is satisfactorily resolved. "Part of the great unknown in all of this is the achievement of the market mitigation requirements of OPG and what the market capacity is going to be for new entrants. Within six months we will have gone from a regulated monopoly to an essentially unregulated monopoly, with the requirement to mitigate over a number of years. But nobody knows exactly what that is going to mean. Nobody knows what the capacity of the nuclear facilities will be. We've been consulted by some large industrial consumers of electricity who are considering building self-generation facilities, with perhaps some excess capacity to sell into the market. Quite frankly, everybody is kind of standing back saying, 'Well I don't know, the rules still aren't set, they're still changing, and we need a little more time to see where it's going.'"

Even beyond the suspense regarding the nuclear capability and the continuing refinement of the complex Market Rules (see A Legal Cornucopia Awaits, Lexpert, May 2000), there are other uncertainties would-be power developers must address says Dominique. "Where am I going to get my gas supply? Where am I going to get my land tenders? Who am I going to be selling to? Can I locate beside somebody who's going to buy the heat or the steam that I'm generating?-that's an important part of my profit component as well. There's a million things that one would have to consider. It all comes down to economics. You're talking about a plant that's going to have a useful life of approximately thirty years, a long term contract may be at least that long, 25 years. It's a huge economic decision and no one has a crystal ball but you want to eliminate your down side risk as much as possible. And people aren't going to jump into this until they see customers lining up."

Kenneth Pearce of Blake, Cassels & Graydon LLP is one of the few experienced energy industry lawyers who did not cut his teeth in the gas industry. Ten years ago, clients of his in the medical technology field left to start a small hydroelectric development company with financing from the venture capital arm of a major Canadian chartered bank. The security for the company's projects was a long-term power purchase agreement with Ontario Hydro, which at the time had embarked on an electricity supply risk-sharing program with private non-utility generators (NUGs). The idea was to download the construction and operational risks to independent power producers in return for "take or pay" purchase contracts at anticipated market rates. Since then, Pearce has acted for a number of other independent hydroelectric and gas-fired cogeneration developers, lenders and investors. His firm also has a group that does work for OPG, though a "Chinese wall" separates them from Pearce and his colleagues who advise the competition.

Pearce's NUG clients who hold long-term power purchase contracts from the former Ontario Hydro (these are now administered by the Ontario Electricity Financial Corporation, one of Hydro's successors) do not have the same problems with uncertainty that they would have if they were looking at doing the same projects today. They are being paid guaranteed rates that are higher than market and are expected to remain so for some years to come. They are part of the excess capacity in the province that will tend to discourage new market entrants, at least initially. "Come November there's not going to be a rush because these contracts are still going to be in existence," says Pearce. "My clients are happy to keep producing power on a long term basis for Ontario Hydro, who saw the need for this power and agreed to pay for it for quite a long period of time. We have to supply Hydro, which can do what it wants with the power as it receives it. If it turned out to be a good deal for Hydro or a bad deal, that's the deal. It's probably going to be a few years before you see a really good market for electricity in the province because of OPG dominance and a lot of smaller players that are locked up for some period of time."

The as of yet unknown fate of OPG's nuclear plants may be depressing activity in some legal offices, but it is generating plenty of hours for those involved in the Bruce Nuclear transaction and the Pickering A environmental assessment. At Torys, which is acting for OPG on both the Pickering A assessment and the Bruce negotiations, Philip Symmonds explains some of the complexities of cutting free a portion of North America's largest nuclear complex, which was designed from the beginning as a functionally integrated operation. Parenthetically, it is worth noting that Symmonds' work at the provincial government's Privatization Secretariat gave him a welcome head start when it came time to sort out the myriad details of an operational separation. "When you're trying to construct a transaction involving just one of these plants, an important area of complexity is how to deal with all the relationships between that plant, the head office, and the other plants. There is a whole unpacking process that you have to go through in designing services delivered both to and from the one plant. There are all kinds of services that are now provided by head office to the different stations and those services may have to continue to be provided after the Bruce transaction. So you have to design those services and figure out what the right fee structure is. You also have to consider issues around liability, and what happens if the separated plant needs help from the workforce at one of the other plants, or vice versa."

Legal Issues For Developers And Lenders
Most energy industry lawyers agree that however many new generation projects end up being built in Ontario, the majority for the foreseeable future will likely be "hybrid" plants where most of the capacity (electricity, heat, steam) will be sold under a long-term power purchase agreement with some "merchant" power left over to sell into the marketplace. A large industrial user, for example, may build a plant on site to ensure that it has a stable, long-term supply of power at prices that will only vary with fuel costs. Or it may contract with a developer to finance, build, own and operate the plant, inside or outside the fence, with some agreement as to what happens with the plant's excess capacity. So if your economic analysis points in this direction, what legal hurdles must be jumped between that decision and when you draw your first kilowatt?

According to Donald Gibson at McCarthys, the legal work begins with the contract structuring of an arrangement that has to anticipate what might happen over a twenty or more year term for electricity, and perhaps water and steam and other energy services as well. Once this is in place, there are financing, environmental, real estate, tax and licencing issues. Permits are key. "A permitting list can go on for 20 or 30 pages. The principal ones are usually the environmental ones, and if you're acting for lenders, you are then trying to get those permits in a form that if your client had to take over the project or sell it to a third party there are no slip-ups when the new party takes over. That's possible in some cases, not in others. Some permits can only be held by the person originally receiving them. So permitting is a big area for lawyers. If you're working for a developer or host plant, you have to anticipate what permits are required; when you're acting for lenders, you review all the permits and often work with the engineering firm that the lenders have hired to do a feasibility and operational review of the whole project."

A key aspect of any feasibility and operational review will be security of fuel supply. For most new power projects in North America today, the fuel of choice is natural gas, which produces far fewer air emissions than coal and which now accounts for 25 per cent of all power produced in Ontario and nearly 60 per cent in the US. Even though the US is the Saudi Arabia of coal, increasingly stringent environmental standards are driving the fossil generation industry there and in Ontario to gas, much of which comes from Western Canada. "Gas and electricity are inextricably linked right now," says Peter Budd of Power Budd LLP. "Developers need to locate where there is a gas infrastructure. That necessarily means that there are going to be rate issues, regulatory issues, and a variety of contractual issues in terms of the takes, the deliveries, the storage, the load factor, and the elements of the gas distributors' unbundled rates."

A former member of the Market Design Committee, Budd now sits on the board of the Independent Electricity Market Operator and is a member of the government's Policy Advisory Committee on Energy. He believes the de facto integration of gas and electricity markets has significant cost/risk implications for those building and financing power projects. "There are two major gas supply issues. One is the transportation from your source. The second one is going to be the commodity itself, where does it come from and how much will you pay? What's happening on the transportation side is that there's a lot of pressure on the transmission service provider to issue shorter term contracts, so that the generators can pick their supply sources on a nimbler, more flexible basis. Historically, TransCanada Pipelines Ltd., which was the largest single provider of gas service to the Ontario area, had ten year service contracts; you couldn't get out of them or de-contract for that period of time. That's turning into a real issue now because prices on TransCanada are expected to go up possibly forty per cent next year, which is unprecedented in Canada. The transmission side of the business often makes up two thirds of the bill to get gas to your plant. That's huge. The commodity itself also has gone up substantially. Unless your electricity cost is tied to gas price increases in some way, which is very difficult to do in the modern world, this imposes huge risks on power developers and their lenders. It's a severe problem. I guess it's what happens when the energy products start to converge and merge and people have competition-even on the transmission side."

Emissions Credits
Budd's firm is expecting a growth in the need for environmental expertise as the recently promulgated air emissions regulations that initially apply only to OPG are eventually extended to gas plants as well. According to Budd: "Our clients are going to have to figure out what makes sense when they go to look at a project package. In any of our facilities applications now we have to consider the security of the gas system, the electricity system, and we're going to be having a look at the emissions impacts at many of these facilities as well. The first two are very linked right now and the third one is sitting right there on the horizon."

Linda Bertoldi, Co-Chair of the Energy Markets Law Group at Borden Ladner Gervais LLP, also got her start in energy law in the early years of Ontario Hydro's NUG program. She worked with a major Canadian developer that built gas generation projects in the North ("before anyone even knew what co-generation was") and has been working in the area ever since, not only in Ontario but also in Nova Scotia and Alberta. Her group is advising a number of industrial clients and municipal electric utilities who are considering their new options, including self-generation. Bertoldi is well-known as particularly knowledgeable in the area of emissions reduction trading (ERT), a specialty area still in its infancy but with enormous growth potential given the early apparent success of ERT schemes and their endorsement by the 1997 Kyoto Accord on global warming.

Under ERT programs, one company's investments in technologies that reduce its emissions below regulatory limits creates government-sanctioned credits that another company can purchase and apply to its own limits for the same substance. It is a way to monetize the environment by making energy efficiency financially rewarding. Critics call ERT programs a "licence to pollute", but supporters say they are working. Total emissions are being reduced and energy efficiency technologies are being encouraged. OPG, as a matter of policy, permanently retires ten per cent of the emissions credits it has purchased to meet its own regulatory limits, credits made necessary by its increased reliance on coal generation because of its nuclear unit lay-ups.

Bertoldi sees ERT schemes as integral to the viability of new power projects. "Emissions trading will be especially important for new projects that are energy efficient and can trade the credits. An interesting question when you're talking about putting together a joint venture is 'who will get the credits?' Is it the party that's buying the electricity, is it the developer, or is there some split? This will be a new revenue source for developers and industrial consumers if they have credits that arise from these arrangements. It is a whole new opportunity, I think, for people to see pluses in a new generation project. If you look at wind projects and some of the smaller water projects, their economic viability will in part depend on this. It is a new element that I think has to be factored in. We've been involved in some wind projects, some water projects and it's very much a front and centre issue-how the credits are going to be dealt with. How you establish what they are worth is another interesting question. This is still something of an unknown but the thinking is that ultimately they are going to be reasonably valuable."

Power Purchasing Risks
The uncertainty facing would-be producers is more than matched by that facing consumers, particularly large industrial users for whom energy is a significant input cost. After all, a potential power project developer can decide the risk isn't worth it and go elsewhere. If you are a manufacturer, this option is not open. You need power or you are out of business. Assuming that you have decided not to self-generate or make a long-term power purchase commitment to a developer to back his facility, you will have two options once the market opens up in November.

The first option is the simplest. You can buy your power from the IMO-administered spot market and later pay whatever you are told the cost of that power was at the time it went through your meter. This is also the riskiest option, as spot market prices can fluctuate wildly, depending on the time of day, the weather, the amount of generation available, and other factors. In the US mid-Atlantic and Midwest markets, for example, electricity spot market prices have been known to rocket in the course of a day from $40 per megawatt-hour to a heart-stopping $10,000, albeit for very brief periods. More common are summer afternoon peak spot prices in the $200-$300 per megawatt-hour range. These are terrifying numbers for CFOs, which is why virtually all large power users are looking at the second option, i.e. contractual arrangements that will protect them from spot market volatility and, hopefully, give them an energy cost advantage over their competitors. But they had better take their lawyer along when they go out power shopping. The new electricity marketplace is no place for neophytes.

Linda Bertoldi works with a number of large industrial clients on power supply issues. She says the first steps are understanding their "load profile"-when is their highest point of demand, how can they control that, how many shifts a day do they run, are there seasonal variations, and so on. After that analysis, the legal work begins. "There are quite a few legal issues around the nature of the contract, the pricing arrangement, the duration of the contract. What type of power do we want? Is it going to be firm? Is it going to be interruptible? What are the consequences if we contract for firm and they cannot deliver? How do we mitigate against that? Are we going to be made whole for our losses? Is it purely a financial contract? Is it a physical bilateral?"

Bertoldi echoes, on behalf of consumers, the caution of power project developers and lenders. "What we are seeing now is nobody wants to commit to anything too long- term because they don't want to be seen to have made a mistake. They want to have some ability to benchmark prices and right now it is not clear what the pricing is going to be on the spot market. So in the contracts we're involved in, people are trying to give themselves flexibility. They obviously want to put as much pricing risk on the provider as they possibly can. They would like to have a fixed price but they don't want to be way out of the money (paying above market) on that price. So you are looking at how you can structure a contract that gives you reasonable protection. Some power brokers are prepared to take a fair degree of risk. And then the question is how good is their commitment? From a legal point of view this is somewhat new territory."

Andrew Roman at Miller Thomson LLP in Toronto spent considerable time advising the Macdonald Committee and the Ontario government on restructuring the electricity market. Roman believes the dominance of the province's nuclear capacity and the fact that they will be "must-run" facilities, will make Ontario's power market the most volatile in North America, at least in the short term. "Where nuclear represents, say, 50 or 60 per cent of the market, and OPG has currently about 90 per cent in total, it's a virtual monopoly. The part that's competitive is very small in comparison and will be very volatile because the larger part will crank a lot of leverage into it. So you're going to see a lot of volatility in the Ontario market which is why trying to predict the price is going to be very difficult." Roman adds that taking the longer view reduces the problem; despite volatility on a half-hour basis, average prices over a month will be fairly predictable. "No one buys power for consumption only for a half-hour." Nevertheless, Roman is taking the mainstream "wait and see" approach to power contracts. "I can advise clients with greater certainty early in the new year when we have had a few months of experience with the market. Things will be a lot clearer then and contracts will be designed to either deal with the volatility or ignore it."

Price may be the biggest concern to industrial clients, but it's not the only major one. Besides the obvious need for reliability, and contractual provisions for defining it, power quality is an increasingly critical factor in supply contracts. Fluctuating voltages are seldom noticeable in lighting or motor performance, but can wreak havoc with microcircuit-driven equipment such as computerized process controls. In many modern industries, "dirty" power can be a serious problem. Voltage stabilization, to ensure "clean" power, has to be part of many power contracts. Roman gives the example of the St. Lawrence Seaway Authority, a client that was for years generating its own hydroelectric power to operate the locks in the Welland Canal. When the Authority converted to automated locks, problems followed. "Because it only had a limited number of generators and because the water flow was the way it was-it wasn't always high enough-they were generating dirty power and the dirty power couldn't be used anymore for the new automated locks which were run by computers. Computers can't use dirty power with wide voltage fluctuations. Another good example is a steel mill that is rapidly rolling out sheet steel. If there is the slightest voltage fluctuation, you are going to get a small bump in the sheet and by the end of the roll there is going to be a huge bump. You just cannot tolerate that and to avoid it you have to pay for a very high level of reliability. You can contractually specify the reliability you need and you can indicate what penalties there will be for not meeting it. If your supplier bears that risk, they are going to charge you for it. So you have to decide how important it is, whether you should internalize that risk and be a self-insurer or whether you should impose it on your supplier and let your supplier deal with it. These are the kinds of things you have to think about when you negotiate these contracts."

Sharon C. Geraghty of Torys often works with economists and engineers in anticipating and weighing her clients' risks before contract decisions are made. Having a commerce and economics background herself, she finds it "challenging to really get inside the head of the business people. You have to understand what they are doing in order to help protect their interests. So the first step is understanding the financial issues, then you have to step back and consider what risks matter and which do not; what you can deal with and what you can't; how you can package and allocate different risks creatively."

Don Gibson at McCarthys anticipates that standard contracts will quickly evolve to simplify power purchase negotiations and he's doing his part to hasten that day. Gibson is currently involved in implementing an arrangement by which in excess of 70 megawatts of Ontario power generated under the supervision of the Ontario Independent Market Operator is transferred to the control of the New York Independent System Operator. He is utilizing the 40-page Master Power Purchase and Sale Agreement recently issued in the US by the Edison Electric Institute and the National Energy Marketers Association, as the basis of this deal. According to Gibson, use of the contract in the US is being phased in and may well become the basis for Ontario contracts. "If you are smart when you are doing your Requests For Proposals for power supply, you will include the contract terms you want in advance so you're not negotiating them after the fact. You'll say 'okay here's the contract I want: the Edison Electric Institute Master PPSA, with the following exceptions.' " Gibson is enthusiastic about contract standardization, despite the fact that it will reduce the need for legal expertise, because he sees it as facilitating the marketplace. "Like the standard ISDA documentation developed for swaps and derivatives, you enter into a master purchase agreement and it contains all of the standard terms and conditions accepted by the industry. But for a particular transaction, you fill in only a couple of pages and that's your deal. It's an efficient way to do business."

ConclusionSo, in November of this year, as I have attempted to illustrate here as well as in the two previous articles in this three-part series on Restructuring Ontario's Electricity Industry, we will enter a period of fundamental change. The stable one-stop shopping system ruled by a publicly-owned monopoly will be replaced by a clamorous swarm of service suppliers and marketers, a dense thicket of regulatory codes and licensing requirements, and an eye-glazing encyclopedia of market rules.

The stakes are enormous. This is a $10 billion market (in annual sales) with billions more in infrastructure. Such UK and US heavy-hitters as British Energy, Pec Energy, American Electric Power, GPU Service, Inc. and Enron have all indicated an interest in expanding into Canada. Yet there is a dearth of information on how the new market will work. For those lawyers and law firms who have the requisite skill set and the ability to move quickly, there exists a window of opportunity to get in on the ground floor of a major new practice area.

This last article on power projects and power contracts continues the central theme outlined in the two previous articles, i.e. there is significant risk and great uncertainty in the new marketplace. Yet, notwithstanding this risk and uncertainty, there is a keen interest on the part of most market participants (or entrants) in ensuring they are not excluded. Underlying all the debate regarding OPG dominance, market volatility, upside/downside risk, et cetera, one senses that Bonetti's Law remains the principal driver for the majority of interested parties, i.e. "The less you bet, the more you lose when you win."


Bill Reno is a Toronto-based writer and communications consultant to the energy industry. He is President of Reno Associates Inc. This article is the third in a three-part series of articles on Restructuring Ontario's Electricity Industry. The first, A Legal Cornucopia Awaits, and the second, The New Deregulated Regulatory Labyrinth, appeared in the May and June issues of Lexpert, respectively.