Tracing the evolution of merchant power plant financing

Sponsored by

Paul Harmon and Bill Reynolds, R. W. Beck Inc.

Lenders tend to be very conservative when evaluating which projects secure funding. In fact, independent engineers, hired to assist lenders in evaluating projects, are often accused by borrowers of being more conservative than they should be—not looking at the glass half-full or not considering the upside.

While it is difficult to disagree that certain events could occur that would result in greater earnings or a more profitable project, always remember that the best thing that a lender can ever hope for is that their debt will be repaid. Even the most successful projects do nothing more than return the loan principal plus some interest, while a disaster could result in losing the entire loan principal. That is why a lender is only interested in funding projects that have a better than average chance of making the payments.

History of power project financing

Prior to the Public Utilities Reform Policy Act of 1978 (PURPA), almost all new generation projects were financed through utility corporate debt, corporate bonds or system revenue bonds. Revenues were essentially guaranteed for regulated utilities through established rates of returns approved by the local public utilities commissions and for non-regulated utilities through the overall system revenues of the utilities.

These power generation projects were generally large and were constructed to meet current electricity loads as well as to meet load growth projections. Risks were small and utility investment was, prior to 1978, typically a safe place to put your money.

New rules resulting from PURPA allowed entities with little or no balance sheet to obtain long-term (up to 30 years) power purchase agreements with creditworthy utilities. To meet PURPA efficiency requirements, most projects during the 1980s and early 1990s were cogeneration or waste fuel projects and were typically relatively small compared to traditional utility-developed facilities.

Revenues from these projects were guaranteed by the purchasing utility, provided specific performance parameters were met. Lenders were willing to finance against these revenue guarantees assuming that the purchasing utility, which was usually a financially-sound entity, would honor the revenue commitments.

The Energy Policy Act of 1992, and subsequent rulemaking, paved the way for wholesale power competition and allowed states the option of creating retail competition. In a competitive environment, utilities could no longer commit to long-term supply contracts, particularly if pricing in these contracts might exceed market pricing.

Merchant plant financing debuts

The concept of "merchant" plant financing emerged in the mid-1990s as a way to finance a power project with no revenue guarantees other than a projected market price at which the facility could sell electricity. Determining the future price of electricity quickly became a huge need in determining the viability of the project.

Projecting the future price of electricity is complicated and is dependent on many variables including: fuel prices, load growth, regulatory requirements, transmission constraints, performance of competing facilities, new technology, market liquidity and other factors.

Developers saw opportunities for projects, especially those based on state-of-the-art gas turbines that were designed to generate electricity at a lower cost than the competition, which would ensure a profit while selling power at market prices.

Since the market price and project revenues were not guaranteed, lenders needed extra assurance that the necessary revenues would be available to pay back the debt. To achieve this, the market risk was pushed back to the project developer through increased project equity, subordination of fuel payments, corporate guarantees and other approaches. Providing additional project support made it difficult for small developers to enter the market and large companies moved to the forefront in project development.

Since increasing the size of the project lowers the cost per kilowatt to construct, projects became larger during the late 1990s. From that period through 2001, project development focused on projects larger than most of the projects that were developed post-PURPA. There was also a trend to combine several projects into the same portfolio and finance them altogether, spreading the risk over several projects instead of one.

Under the portfolio approach, if a particular project fails to generate sufficient revenue, the remaining projects are expected to have sufficient margins to enable debt repayment. Financing numerous projects at the same time requires from several hundred million dollars up to $1-2 billion in capital. These capital requirements are far greater than a single, or even a few institutions, are willing to provide, thus more participants are required. As the number of participants increases, the complexity and difficulty of project financing does as well.

Future trends

Technical people like to believe that a well-designed and well-constructed state-of-the-art generation project should be easy to finance. However, the common thread in successful power project financing has always been, and will always be, a guarantee of the revenues.

In addition, merchant plants will also have to be the most cost effective plants within the marketplace or the revenues will flow to the projects that are more cost effective. Current market conditions are uncertain, at best, with high fuel prices and low spark spreads. The resulting revenue uncertainty will prevent the development of new power generation facilities unless a long-term and creditworthy buyer signs a contract.

Investor-owned utilities (IOUs) are not guaranteed a rate of return on investments to the extent they once were and there are no incentives in place to invest in excess capacity to anticipate future load requirements. In addition, most utilities are not interested in entering into long-term power purchase agreements for the same reasons.

As load continues to grow and developers become more reluctant to build new generation, we will eventually reach a point where demand exceeds supply and power prices will spike.

These higher prices will provide the incentive to build new generation facilities until supply once again exceeds demand, causing power prices to fall and development to, once again, be curtailed. However, the timing of this price signal may not provide sufficient lead time to site, permit, finance and build new generation, with the result that the duration of the resulting generation shortfall could be measured in years.

Non-regulated utilities have been relatively inactive in the past few years and have been waiting on the market to provide a stable power supply. Based on historic open market failures, some of these utilities, at a number of locations around the country, are willing to sign longer term contracts or even build their own revenue bond-financed generation facilities.

The recent boom in the building of new generating plants has, in many cases, made use of the best sites in terms of proximity to market or to transmission facilities sufficient to move output to markets some distance from the plant. With the absence of significant new transmission construction, future generation additions are likely to have difficulty finding sites from which output can be economically moved to market. This will add to the difficulty of financing such projects, since these limitations can significantly impact the revenue stream.

Merchant power plants have risen swiftly from virtual non-existence less than seven years ago to become the dominant form of generation addition today. While the success of the concept has been demonstrated, the future will depend largely on the ability to attract sufficient amounts of affordable capital. Together, with generation additions by utilities, the addition of merchant power plants nationwide has created transmission system challenges that will impact the selection of sites for future generation additions.

Harmon is a principal with R. W. Beck in Denver. He can be reached at pharmon@rwbeck.com or 303-299-5244. Reynolds is a principal with R. W. Beck in Orlando, Fla., and can be reached at breynolds@rwbeck.com or 407-422-4911.

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POWERGRID International

March 2014
Volume 19, Issue 3
1403PG-cover

ELECTRIC LIGHT & POWER

January 2014
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