• Financing Merchant Power Plants in the United States
  • May 6, 2003 | Author: Keith W. Kriebel
  • Law Firm: Orrick, Herrington & Sutcliffe LLP - Washington Office
  • Last year in this space our colleague Michael Meyers extolled participants in US project finance to "embrace change." He was writing in the context of describing financing techniques, with "project finance" now being merely one item on a menu of choices for developers of power projects and similar ventures. The underlying message was that the ongoing restructuring of the electric utility industry in the United States has changed the paradigm of power project development and financing. While it can safely be said that the Public Utility Regulatory Policies Act of 1978 (PURPA) was the prime mover (however unintended) behind the development in the US of the independent power project (IPP)-a generator, not owned by an electric utility, that makes wholesale sales of electric energy and, frequently, capacity, under long-term off-take contracts with deep-pocket electric utilities-PURPA now has become almost irrelevant: the success of the IPP and industry and consumer demands for cheaper power have led to changes in law mandating competitive electric generation pricing and the disaggregation of utility asset ownership. As PURPA recedes in importance and its repeal (prospectively as to new projects) becomes more likely, there probably will be no future role for Qualifying Facilities-non-utility generators that meet certain ownership and technical criteria specified in PURPA-and only a limited future role for IPPs.

    The existence of a freestanding market for the generation and sale of electricity as a commodity into regional power markets will lead to a significant role for the merchant power plant: a generator that sells much or all of its output directly into the spot electricity market. Being able to secure project financing for the merchant plant requires an understanding of its unique and not insignificant risks.

    Merchant Power Risks

    The risks associated with merchant power plants can be classified into three major categories: market risk (which includes the markets for the sale of electricity and for the purchase of fuel), project risk (which includes construction, technology and operating risks), and structural risk (which includes legal/regulatory and financing risks). Some of these risks are more subject to control than others. The risks that cannot be controlled adequately simply must be allocated among the project participants in a logical way (the standard refrain is to say "the risk is allocated to the party in the best position to accept the risk"). If the risks cannot be controlled or allocated, the project will die.

    Market Risk
    Market risk quite properly receives the lion's share of attention when it comes to evaluating planned merchant facilities. Until recently the developers and owners of IPPs have not needed to worry about market risk on the electricity sale side: once a power purchase agreement had been signed, the major "market" risk effectively was whether the utility remained willing and able to honor its obligations under the contract. Since, in the "pure" merchant model, there would be no negotiated power purchase agreements between the generator and its off-takers, the market itself would determine the periodic price of electric energy and capacity and the generator would either sell at that price or not. Obviously, the ultimate success of a merchant plant is dependent upon its ability to produce electricity at a total cost to the generator, including all debt service, which is, on average, less than that for which the market will pay for such electricity throughout the life of the project. Far from obvious, however, is any method for accurately forecasting the future market price of electricity or, to a somewhat lesser extent, the generator's cost of production.

    In attempting to minimize the risk associated with the future market price of electricity in the region to be served by a proposed merchant power plant, several considerations must be addressed, including the presence-actual or likely-of other generation providers within the region, the likelihood of electricity "imports" from outside the region, transmission constraints, and the future regional demand for electricity.

    The very structure of the market in which a proposed merchant plant intends to operate is at the outset defined largely by the power providers already operating or supplying power in the region. Are the existing generators currently providing, or are they capable of providing, sufficient electricity to the region at competitive prices? What type of technology is currently being used? What is the life expectancy of the current generation, and is repowering of the same expected to be feasible? Will new competitors enter the market in the future, or will existing competitors expand their generation facilities? In making these assessments, one needs to consider the availability and location of potential generation sites, the financial and marketing strength of potential competitors, the possibility that any competitor will utilize a production technology that is more efficient than that of the proposed plant, and the potential for regulatory changes, such as opening a region to imported power from neighboring regions.

    Because the financial viability of a power plant is dependent upon its ability to efficiently deliver electricity to its potential customers, the supply risk is further influenced by transmission constraints, including transmission pricing policies and transmission availability. For example, in areas of high congestion during periods of peak load, some transmission systems use a congestion pricing scheme to pay generators different prices based on their respective locations relative to transmission constraints. Accordingly, the location of a power plant will influence the price paid to the generator in areas that use such pricing schemes. Furthermore, even if a plant is favorably sited as an initial matter, there is always a risk that the transmission system will change its pricing scheme or invest in increasing the capacity of the grid, thereby eliminating the benefit from congestion derived by the well-sited facility.

    An assessment of market risk must also forecast the demand for electric power in the region over the life of the project. Generally, a useful starting point in analyzing future electricity demand is assessing the strength of the local economy and its potential for growth. The evaluation should include demographic studies as well as a forecast of industrial growth, since each will have a unique impact on future demand. For example, retail customers may eventually continuously shop for the lowest electricity price among providers, as is currently the case with respect to telephone long distance companies. On the other hand, industrial users may prefer to lock-in a slightly above-market price from one provider over longer periods as a hedge against rising electricity prices, shifting importance somewhat from price level to price certainty.

    Despite attempts to improve the accuracy of marketing forecasts, because they are forecasts they are certain to be inaccurate to some degree. This has particular poignancy in the electric industry in general and the IPP industry in particular, given assumptions used in forecasts of avoided costs in the early and mid-1980s that the price of oil would reach $100/barrel by 1990. More recently, the demand for electricity experienced in California and in the Midwest during hot weather in the summer of 1998 caught the industry unprepared and with insufficient capacity to handle the resulting loads that resulted in dramatic price spikes.

    Given the uncertainty inherent in all forecasts, particularly those analyzing areas such as electricity for which no market previously existed, developers seeking project financing must seek to mitigate market risk. For most merchant plants developed to date, mitigating market risk simply has meant lessening the project's reliance on the marketplace and moving to the familiar cover of the term off-take contract. These so-called "hybrid" merchant plants offer developers a great deal of flexibility because the off-take contracts can be structured to utilize all of a facility's output for a given period of time (usually tied to the greatest amortization of the project's debt), or to cover only part of the output, leaving the remainder available for sale into the open market.

    Of course, the reliance to any meaningful degree on mid- to long-term off-take contracts requires the purchaser(s) to be creditworthy and to have appropriate incentives to perform for the term of the contract. If the contracts are with electric utilities, sellers will need to know how the utility (and the state in which it is located) intends to deal with restructuring so its continuing financial strength can be evaluated. Siting plants in industrial parks or building an oversized "inside-the-fence" facility for a major electricity consumer such as a steel mill, oil refinery or paper mill may prove ideal, since sales to the captive customer can cover fixed and variable operating costs and debt service, and profit can come from sales into the grid. Given the new opportunities available to major electricity consumers to satisfy their power requirements, entities agreeing to host inside-the-fence projects recognize their importance and insist on participating in the economic benefits of the project.

    Where consumers have provided the impetus for a project and want to control most or all of a project's output (as, for example, where a refinery is seeking to remove a fully amortized utility plant from its books or wants expanded or upgraded service), the off-take contract may take the form of a tolling agreement. Under a tolling agreement the generator simply converts one form of energy, the fuel (often natural gas) into another, electricity. The customer determines when and how much electricity should be produced at any given time. The generator, of course, will need to have certain minimum cash flows to cover fixed costs incurred regardless of whether the facility operates. Thus, the customer either has to guarantee a certain amount of purchases (effectively a take-or-pay arrangement), or pay a capacity charge for the generator's being available. Tolling agreements also can be used by fuel suppliers who determine that converting fuel into electricity would yield a higher return than simply selling the fuel at a given time. Again, the tolling agreement must be structured to ensure the generator receives sufficient funds to cover its fixed costs, while providing for dividing the upside between the fuel supplier and the generator. Suppliers and consumers also can agree to use what amounts to an internal hedging arrangement under which the parties share the risks and rewards of swings in market prices.

    Since fuel typically is the most significant component of a project's operating and maintenance costs, market risk also subsumes the future availability and price of fuel. As discussed above, accurately predicting the future price and availability of fuel has proven to be difficult. The long-term, fixed- or formula-driven-price fuel supply contract favored by IPPs (which effectively was mandated by financing entities to eliminate fuel/electricity price mismatches) has only a limited role in merchant plants given the risk that fuel prices could unexpectedly drop, leaving the generator with a non-competitive fuel cost. Presumably there could be long-term contracts at prices so favorable that such a risk is insignificant, but those contracts will be rare. Generators using waste fuels, particularly those who already own or control significant reserves, will have an advantage in the dispatch queue, but face substantial up-front costs that will need to be funded. Projects operating under tolling agreements avoid most fuel issues, but find their upside limited because they cannot take advantage of fuel arbitrage. Other projects may mitigate fuel market risk by entering into supply arrangements with fuel prices tied to electricity prices. Still others may use fuel management plans that include hedges. There are innumerable combinations of mitigation techniques, but finding the right combination for a particular type of project in a particular location requires a great amount of skill.

    Project Risk
    The project risk associated with merchant power plants is quite similar to that associated with traditional IPPs and, accordingly, it should not be viewed as presenting any greater or fewer challenges than would be true for IPPs. The one difference is that merchant plants need to be particularly circumspect about cost. The now-traditional fixed-price, turnkey engineering, procurement and construction contract carries with it a substantial premium benefiting the contractor, and as such is likely to be shunned by developers with sufficient internal technical and financial resources to assume the turnkey role themselves. In some respects, this represents a return to the early days of IPP development when a turnkey "wrap" was unusual, but it is a tool available only to well-capitalized and experienced entities.

    Financing entities will be especially focused on technology risk, since the cost of problems with unproven technologies could prove fatal in a merchant context, while the potential efficiencies of new technology could allow a successful plant to be much more profitable. Typically, the vendor is in the best position to accept this risk, at least through the initial period of operation, through contractual warranties and design guarantees. Vendors anxious to establish their technologies as viable in the merchant context can be expected to take significant portions of technology risk, but to be of real value, vendors must be financially capable of shouldering potentially heavy burdens. Ultimately, performance, rather than remedies, is what both owners and financiers desire, so even well-crafted warranties from substantial vendors may not suffice in the case of truly unproven technologies and, in such cases, the vendor may need to put on the developer's hat and be prepared to put substantial equity at risk in order to promote its technology.

    Structural Risk
    Project legal, regulatory and financing structures constitute the last large category of risks that must be addressed. Legal and regulatory stability, while central in the development and financing of any project, is imperative in the merchant context given the need to avoid costs that make a project non-competitive. To the extent that all participants enjoy a level playing field, the market itself should accommodate surprises and most producers, assuming their projects have the solid financial structures we discuss below, will adapt. To the extent, though, that some participants face change and others do not, regulatory changes could have significant impacts on a project's ability to compete. This is exemplified by one recent change that those affected are still trying to understand and address.

    Since merchant plants are dependent upon the transmission network to reach potential purchasers, the regional rules governing interconnections, transmission access and pricing will necessarily affect a project's economics. Those rules typically are established by the independent system operator (ISO) or similar entity, after input from interested parties (including generators, consumers and owners of transmission facilities), subject to oversight and review by the Federal Energy Regulatory Commission (FERC). FERC has shown that it will overrule regional transmission organizations in these matters if it finds the proposed rules to be unreasonable or discriminatory. For example, until recently in New England, transmission rules required that all new generators seeking interconnection with the transmission grid show, through system impact studies, that the transmission system had the capacity to deliver the planned generator's electrical output to every load-serving entity in the New England Power Pool (NEPOOL), covering a region from Maine to Massachusetts. This had clear negative implications for new generators seeking to sell power into NEPOOL, since, based upon the number and location of proposed new generating plants in the region, transmission "bottlenecks" were projected to occur. After negotiations among affected interests, the ISO adopted a rule whereby a new generator would be required to pay for at least one-half of the system upgrades needed to alleviate the bottlenecks caused by that generator. FERC ruled, however, that the New England ISO must limit its analysis of proposed interconnections to system reliability, stability and operating considerations, while deferring its ruling on how any upgrade costs would be assigned until a transmission congestion management system is developed.

    Currently, a pitched battle is underway in New England over how to allocate the right to receive compensation when transmission constraints cause the price of power to vary at different locations within NEPOOL. NEPOOL's proposal would allocate these rights to transmission customers paying for firm transmission service and to those who were receiving transmission service before NEPOOL was restructured. The generators in New England, however, particularly those who acquired their assets through divestiture, argue that at least a portion of these congestion rights should be allocated to them. FERC's rulings on these issues could have a dramatic impact on the economics of both existing and planned generating plants in the region. The risk always exists, moreover, that whatever regime is initially adopted in a given region could later be modified at the behest of the regional transmission organization, by FERC or by a state commission. In many respects, then, choosing to locate merchant plants only in markets where regulatory schemes are mature may be the only way to mitigate this risk.

    Just as new legal and regulatory risks must be addressed in developing merchant facilities, the unique financial risks faced by merchant plants also require creative responses. While the entities financing a traditional IPP could in most cases look to the relatively simple analytical framework of a long-term purchase contract and a creditworthy electric utility, financiers of merchant power plants are required to analyze many more factors that affect or potentially could affect the cash flow of a particular project. The key to successfully financing merchant power plants on a "project finance" basis will be to craft a financing structure that both anticipates and responds on a real-time basis to dynamic changes in market conditions.

    There are a number of standard financial tools used in the financing of IPPs that, with some minor adjustments, will also play a significant role in the financing of merchant power plants. Appropriate use of these tools can build resilience into merchant financing structures by creating more robust capital and economic foundations that can absorb potentially significant swings in performance (both internally and externally driven). These tools include substantially higher debt service coverage requirements than are found in traditional IPPs, initial equity commitments on the part of the sponsors that are as much as twice those of IPPs of similar size, and full funding of reserves, such as those for debt service and operation and maintenance, earlier and at higher levels than in traditional IPPs.

    After the more substantial foundation has been laid, the next step is to create a structure able to respond in real time to changing market conditions. This responsiveness may take the form of any number of the following: (i) requiring independent economic analysis on a periodic basis of market conditions and performance, the results of which may limit distributions of residual cash to sponsors, as well as tighter overall restrictions on distributions of residual cash to sponsors; (ii) building covenants into the financing structure which require trapping cash if certain changes in market conditions occur; (iii) requiring a predetermined percentage of cash flows above certain debt service coverage levels to partially prepay debt; (iv) requiring contingent equity commitments on the part of project sponsors which can be utilized if certain market and/or performance conditions arise; and (v) in the case of hybrid merchant plants, using front-end loaded amortizing debt that builds upon greater predictability of cash flow in the early years of the project.

    The ability to transform detailed market and performance analyses into a set of "living" financing documents is likely to be an exciting and challenging aspect of developing successful financing structures for merchant power plants.


    Earlier this decade, independent power development activity in the US diminished significantly when utilities stopped entering into long-term power purchase agreements, some having felt victimized by PURPA contracts and all seemingly determined not to repeat that experience in the face of the utility restructuring that could be glimpsed just over the horizon. Instead, project developers focused their attention on the international markets, particularly Asia, South America and Eastern Europe. Now, utility restructuring is well under way in the US, with retail access, disaggregation and divestiture occurring at an ever-increasing pace, while competition at the wholesale level has firmly taken hold and capacity shortages have become manifest in certain regions of the country. Still, with rare exception, even those utilities that retain an obligation to serve native load customers have shown no inclination to either build new generating units or to enter into long-term, fixed-price power purchase agreements.

    Merchant power plants, both pure and hybrid, have stepped into the void and are now the consensus choice to meet this country's power demands in the 21st century. Financing these projects, particularly pure merchant plants, is a difficult and challenging exercise requiring creative and often complex solutions to manage the many risks. The first generation of merchant plants has mitigated some of these risks by contracting to sell a portion of their output under fixed-term contracts and by locating in those regions of the country where the newly-created regulatory regime is the most well established. But the planned capacity for some of those regions is beginning to exceed demand and finding a dedicated purchaser for even a portion of a plant's output is not always possible. So the next generation of merchant plants, to be successful in making it from the planning to the operational stage, will need to implement many, if not most, of the risk mitigation measures that have been described. While not an easy task, those who succeed, like the early PURPA pioneers, should be rewarded with substantial returns on their investments.