Business & Money
A review of power plant deals in 2004 shows that utilities are buying.
Sales of merchant generating facilities during 2004 signaled several trends that illustrate how the power business is evolving. After a nadir in 2002, sales turned up during 2003 and then more than quadrupled during 2004. The backlog of merchant plants for sale is thinning. Buyers and sellers are closing the spreads that led to much talk but few actual sales.
Whether evolution or devolution, the merchant deals done to date show movement to a familiar structure; ratepayers are back at risk. While ratepayers have benefitted from merchant plants, they also paid since competition began with PURPA in 1978, and many of the acquisitions put them at risk for future changes in power values and fuel costs.
The Boost in Deal Volume
More than 18 transactions involving more than 30 merchant power projects are now pending or closed. Examples of these transactions are summarized in Table 1 (). This exhibit presents aspects of the buyer, seller, name, location, timing, capacity, fuel, and value associated with each transaction.
The 18 sales involve 102 different power projects and net installed capacity sold of more than 14,350 MW. Reliant's sale of the Orion portfolio to Brascan included 72 hydroelectric projects and without this transaction, the scorecard to date includes 30 projects and an aggregate net capacity sold of approximately 14,000 MW. Nearly all of these are natural-gas-fired combustion, turbine-based projects constructed when the merchant business model appeared to be viable. These sales include 30 percent to 50 percent of the total merchant capacity built during the last five years. While the merchant sector is far from sold off or abandoned, these sales show that substantial progress has been made in that direction. Buyers and sellers are finding acceptable methods of allocating risks, and the spread is closing between bid and asking price.
Three examples demonstrate the evolution of merchant power and events that led to recent sales. First, the sale of the Frederickson plant to Puget Sound Energy closed during mid-2004 and involves an "accidental merchant" with a storied history. The project was developed during the early 1990s by Tenaska and was supported by a power-sales contract with Bonneville Power Administration (BPA). BPA terminated the contract while the project was under construction, and years of litigation and restructuring ensued. BPA became the owner, and EPCOR Power Development of Alberta ultimately purchased the project from BPA. EPCOR completed construction, and operations began during September 2002. Puget Sound Energy (PSE) announced its intent to purchase an interest in this project for $76.4 million plus approximately $4 million for upgrade costs. Closing was contingent upon timely approval of full cost recovery by the Washington State Utilities and Transportation Commission, and PSE's ratepayers now bear the risks associated with the acquisition, as well as power values and fuel costs.
More typical of merchant experience are Brazos Valley and Duke's southeast portfolio. NRG developed Brazos Valley, and construction was well under way during 2002 when NRG became unable to meet its equity funding commitments. The lender group foreclosed during January 2003 and, following much evaluation and a restructuring of their interests, funded the completion of construction during mid-2003. An extensive marketing effort and several false starts ultimately led to Calpine's purchase of the 570-MW project.
Duke Energy North America (DENA) developed numerous merchant projects and had a portfolio of eight projects in four states in the Southeastern Electric Reliability Council (SERC). All eight are natural-gas-fired, five are peakers, three are combined-cycle facilities, and most of their 5,280-MW combined capacity went into service during 2002. As DENA's heavy investment in merchant generation failed to yield current earnings, asset sales began. Lackluster bids forced DENA to write down the value of the plants three times and the portfolio ultimately was sold to KGen Partners (KGgen). In addition, as part of the deal, one of the projects is supported by a power-purchase agreement with Georgia Power. KGen is owned by MatlinPatterson, a distressed-debt-focused fund that also invested in NRG Energy and has a representative on NRG's board of directors.
Standing back, the transactions dicussed here show that sellers are primarily the developers and lenders who invested heavily in merchant generation. Buyers are diverse-utilities, independents and private equity firms. Utilities of various types actually account for most of the transactions. Investor-owned utilities, munis and other entities whose ratepayers will be at risk account for approximately 70 percent of the transactions, 45 percent of the generating capacity and 50 percent of the value exchanged. Among independents, Calpine has been both a buyer and seller. Private-equity firms have spent much time looking for a merchant acquisition; however, few have become buyers. KGen was noted above. Brascan and Centrica have other power interests and experience.
Private equity buyers actually have been more active in pursing generation that involves less risk than merchant operations-either regulated utilities or non-merchant independent power. Texas Pacific Group formed Oregon Electric Utility Co. to pursue acquiring Portland General Electric from Enron. KKR, Blackstone Group, Texas Pacific Group and Hellman & Friedman have joined to purchase the former Reliant unit Texas Genco. AIG, Algonquin, Arclight, Goldman Sachs, Harbert and many others have, and continue to, pursue projects whose revenues are secured by long-term contracts.
Buyer's Market: Finding Value
Merchant sales have been painful experiences for sellers. Continuing with the examples of Frederickson, Brazos Valley and Duke, those interests sold for approximately 79 percent, 68 percent and 20 percent of original cost, respectively. While the range is broad, on average, operational natural-gas-fired merchant projects have sold for approximately 55 percent of the actual total cost to develop and construct. Such discounts are not isolated to completed projects. Some combustion turbines still under warranty and in factory wrap are worth only 50 percent of their actual cost of three years ago. Economic recovery, regulatory changes and new needs for capacity are starting to reverse the slide in some markets.
The $/kW is an often employed and potentially reckless guide to value. Subject to that qualification, prices varied between approximately $90/kW to $790/kW and averaged $225/kW for operating gas-fired plants. Low-value projects tend to be combustion-turbine peakers with heat rates over 11,000 Btu/kWh in regions such as SERC and the East Central Area Reliability Coordination Agreement, which have ample reserve margins and substantial coal and nuclear generation. The Duke GE 7EAs in Georgia, Kentucky, and Mississippi purchased by KGen are examples. High-value projects tend to be combined-cycle facilities with relatively low heat rates purchased by ratepayer-at-risk entities. The purchases by Avista, GenTex, Puget Sound Energy, and city of Brownsville () are examples.
While $/kW is a popular measure of value, a project-specific forecast of net income is a universally employed and more reliable guide to value. Discounted cash flow (DCF) remains the gold standard of valuation. Due to uncertainty surrounding operations, power values, and fuel costs over time, several scenarios and probabilistic Monte Carlo results also are often considered. While a facility currently might be out of the money due to its heat rate and non-fuel variable operating costs, changes in markets over time, and a focus on high-value time periods may support some capital value. For example, such analysis is the only way to support capital value for the DENA and NE> peakers purchased by KGen and American Municipal Power - Ohio.
One of the critical inputs to DCF valuation is the discount rate or rate of return that a buyer requires. As a benchmark, power projects with contract-secured revenues and costs will sell for pre-tax returns of 14 percent to 18 percent. Some high-quality, low-risk projects sell for more aggressive returns, and those with resource risk, technology risk, or that have defects in key supporting agreements demand higher returns.
After tax, the return range for high-quality projects is in the single digits to low teens. For merchants, due to comparatively high risk and complexity, rate-of-return thresholds become less meaningful. For example, buyers might focus on adverse circumstances and bid only what appears to be a break-even price. They may be willing to risk a positive return on uncertain markets. Differences among bids more likely are determined by how they view the risks than the rate of return each requires.
The Implications of Reintegration
Reintegration by regulated utilities through merchant acquisitions is, in many respects, controversial. First, it represents a concentration of ownership and potential loss of the benefits of competitive power markets. Several of the acquisitions by regulated utilities have been controversial for other reasons. Arizona Public Service purchased five projects from its affiliate Pinnacle West, and some allege that the price paid represents a bailout at the expense of ratepayers. Edison's arrangements concerning Mountain View were negotiated and not the results of a broad competitive solicitation for new capacity. A contract with an affiliate also is involved. Interveners in proceedings at the California Public Utilities Commission asserted that the transaction is a bailout, allowed concentration of generation, and reduced the role of independent generators in California.
While the current opportunity to purchase assets for prices below what they cost to construct appears attractive, a focus on discount can miss an important point. Such a focus is backward looking, and value ought to consider the future. Coal-fired and other non-gas assets, for example, might be worth more than they cost to construct because of the fuel diversity and other benefits they provide. As market prices for coal have increased along with gas prices, the values of generating facilities fired by fixed-price coal have increased.
Many existing projects with fully contracted revenues and costs also involve an element of merchant risk. What is contracted now will at some time become merchant, and buyers of contracted projects must consider such project's merchant residual value or "tail." Buyers' methods vary. One approach is to take pure merchant prices today, inflate them forward to the residual period, and then discount them back. Another is to estimate operating margin during the tail and then discount that value back at a rate that reflects higher risk. A third is to apply a conservative multiple to a forecast of earnings during the first year of residual period operations. B&Co has seen 5 times earnings before interest, taxes, depreciation, and amortization (EBITDA) applied to relatively near-term forecasts, and 3 to 4 times EBITDA applied to values 20 and more years in the future.
Finally, the merchant business model is evolving. It has not been entirely abandoned for a return to long-term power contracts that are supported by utility balance sheets, regulatory commissions and ratepayers. While many future projects will be supported by such contracts, and those currently being proposed by Pacific Gas & Electric and the New York Power Authority are examples, hybrids are on the horizon. "Hedged generation" in the lexicon of the deal structure involves projects supported by contracts that track what a project can sell and allow owners and lenders to manage operating margins. Long-term fuel contracts with prices that are arithmetically linked to power values are an example. Wind projects in gas-dominated systems that use long-term gas contracts to hedge power value are another.
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