'First movers' will be positioned to extract the most value from the acquisition of generation infrastructure.
When it comes to the current climate for generation asset sales, a wide bid/ask spread has developed between the buyers' offer prices and sellers' target sales prices. We have dubbed this bid/ask spread the "distressed asset gap." Sellers are looking to maximize the liquidity generated from asset disposals, while opportunistic buyers are looking to capitalize on industry dislocation to acquire assets for a fraction of their original build or financing costs. Until this gap closes, transactions will not be widespread.
To gain an understanding of why there have been few sales or purchases of distressed assets, it is important to understand the perspective of each of the parties involved in this process and how the distressed asset gap was created.
IPPs
Despite highly leveraged balance sheets and poor liquidity positions, many independent power producers (IPPs) are reluctant sellers in the current depressed power market environment. These companies believe that the prices being bid for their assets reflect a temporary undervaluation of assets that have useful lives of several decades. These assets, they believe, should not be relinquished for bargain basement prices due to a sharp, temporary decline in power markets.
There generally are two classes of sellers in the market. In the first and healthiest category are the IPPs still in control of their own destiny and engaged in an orderly auction process. These companies have the larger liquidity cushion and some ability, although limited, to time the market (i.e. to wait for a price that, in their view, is more reflective of the intrinsic value of the asset.)
In the second category are the IPPs with senior lenders and bondholders (as a result of both technical and substantive defaults by the borrower) leading an involuntary restructuring. In the cases where creditors are in control of the asset disposal process there is a growing awareness that a messy and chaotic liquidation of billions of dollars of assets is not in the interest of either the IPPs or creditors.
Those IPPs that retain some measure of control over their destiny and therefore remain reluctant sellers believe that tomorrow is likely to be better than today. The only question is, when will tomorrow come?
For most of these companies, only the sale of the best and most valuable assets will generate enough cash flow to materially improve their liquidity position and de-leverage their balance sheets to more prudent levels, but if these companies are going to have any chance of remaining viable independent entities, these are precisely the assets they need to hold on to. Consequently, these IPPs have tried to defer the sale of their crown jewels and have focused on selling their more marginal assets that have been of little interest to potential acquirers.
Project Finance and Corporate Lenders
The lenders that have funded the explosion in IPP capacity have found themselves caught in a classic maturity mismatch-long-lived assets were funded with short-term financial structures. Most distressed assets were financed with highly leveraged three- to seven-year maturity, mini-perm facilities that relied on volatile and highly uncertain pricing and regulatory environments to bridge the gap until an eventual long-term refinancing in the capital markets.
Lenders now find themselves presiding over the sale of assets to maximize loan recoveries in a tough market with a glut of assets for sale, a supply/demand imbalance, and little incremental appetite or ability on the part of the usual market participants to allocate more credit or capital to the industry. Without the looming requirement to refinance more than $45 billion of medium-term debt within the next 36 months, it is arguable that IPP balance sheets would be under tremendous duress in the near to medium term. Lenders are therefore faced with realizing a short-term valuation on a long-lived asset due to the original short-term financial structure.
Some lenders have recognized the incongruity of this situation and have stepped back from making precipitous decisions regarding acceptable levels of recovery in the heat of the moment. Moreover, lender workout groups are practiced in maximizing available cash flows to meet debt service and taking other measures to avoid a distress sales situation. While this process has been going on there has been little interest in closing on the sale of assets, except where the level of the recovery of outstanding debt is close to 100 percent.
As a result of this pause, some creditors have started to consider other options. These lenders have taken the time to carefully assess when and under what structure-including a workout mode versus bankruptcy-is the appropriate time and framework to liquidate their positions. This perspective is important because there is incentive to avoid a sale today and maximize value tomorrow. However, waiting until tomorrow causes its own set of issues and challenges.
Project finance lenders may also have a little-noticed regulatory motivation to proceed cautiously with the sale of distressed assets. In 2001, the Basel Committee on Banking Regulation issued proposals for a New Basel Capital Accord ("Basel II") that, once finalized, will replace the current 1998 Capital Accord. The Basel II proposals say that asset-backed project finance lending is inherently riskier than unsecured corporate lending and therefore requires a higher risk-weighting and a larger allocation of regulatory capital.
Leading project finance lenders protested that the rules as drafted threatened the long-term viability of project finance lending and would result in increased pricing to borrowers and reduced credit capacity. The project finance banks argued in submissions to the Basel Committee that based on an analysis of their own portfolios, project finance loans have exhibited higher rates of recovery in default due to the credit enhancements that normally are a feature of asset-based lending, and that less and not more capital should be required to reserve against expected losses.
In the face of a more significant downturn in the project finance lending business, these same lenders will be increasingly focused on minimizing any losses taken on their project finance lending and will be strongly motivated to maximize recoveries to protect not only their previous positions with the Basel Committee but the long-term health of the industry as a whole.
When Will a Round of Selling Occur?
The first step to a significant round of asset sales is when lenders transfer asset control to well-seasoned workout specialists. These workout specialists, although not power industry experts, have weathered the demise of the financial, healthcare, dot-com, and technology industries. Extremely capable individuals, aided by energy and bankruptcy experts, are forming steering committees to analyze and extract all current tangible value from the distressed electric generation assets. While this takes time, several companies have been unable to restructure their debt and may soon be forced to sell.
Secondly, a new group of players is forming to acquire assets. Since depressed industry fundamentals, poor short-term liquidity, and the lack of access to equity and capital markets have impacted virtually all of the players connected to the U.S. merchant market, the companies most knowledgeable of the market and, to some extent, most bullish on future prospects are not capable of buying these distressed assets. Consequently, new equity is entering the market. This equity is split among traditional private strategic equity and equity funds, including hedge funds chasing outsized returns. However, each of these participants faces challenges in allocating their capital to the industry.
The problems with these entrants are:
- Lack of market knowledge that contributes to a conservative approach to asset valuation;
- Lack of management capability that makes them hesitant to buy single assets without a supporting management structure; and
- Inability of capital alone to solve or halt the slide in asset values.
Traditional utilities could fill the distressed asset gap and create significant value in the process. They have the market knowledge, the management capability, and the capital to find value in this market if they are willing to consider both acquisition and options that assist lenders and IPPs.
Lender credit committees are waiting to see if market prices recover. Hedge fund managers are waiting to see if prices drop further. Utilities are exercising market power and taking advantage of transmission constraints, e.g., call option prices at the marginal cost of generation. The big question is who will sell or buy first.
Creating Value in the Current Market
The current depressed market for power generation offers unprecedented value creation and risk mitigation opportunities for utilities seeking to acquire capacity or contracted power supply. Utilities have emerged as among the best positioned to take advantage of the current overbuild, financial crisis, and regulatory uncertainty plaguing the merchant power community. Utilities are in a position to acquire assets at relatively low prices and to potentially embed them in their rate base or, at a minimum, to leverage their load resources and credit rating to obtain preferred financing terms.
At one extreme are utilities that find themselves short on economic generation, with both outstanding load obligations and a regulatory framework intended to maintain or extend their service obligations. Utilities in this class will be best positioned to enhance their generation supply portfolio by taking action to purchase or contract for term generation capacity from among the pool of distressed assets. This is particularly the case if these utilities enjoy access to a relatively high concentration of distressed merchant assets in or connected to their load area. At the other extreme, a utility may be limited in its capacity to embed generation in its rate base, or it may find few assets compatible with its load service or financial constraints.
In assessing generation acquisition or contracting opportunities, utilities are evaluating a variety of approaches to financing acquisitions or otherwise stepping into assets that present opportunities to convert from a contract to an ownership position. From a financing perspective, municipal and regulated utilities are less motivated to seek high rates of equity return as investor-owned utilities and other buyers, but they are motivated to acquire supply at relatively low and stable rates, given their regulatory (prudence) review criteria. Some of the more attractive approaches and capital combinations that are emerging in today's market include:
- Use of flexible loan structures, with equity return features and conversion rights granted to the lender, and the acquiring utility providing term contract commitments to support the asset's underlying collateral value;
- Load-backed acquisition utilizing a project finance structure with accelerated interest and principal payment rights to lenders, potentially serving as a framework for the next round of limited utility-backed generation project financing;
- A sale-leaseback structure, whereby the utility may act as lessor or lessee depending on its ability to place the asset in its rate base and its comparative depreciation benefits relative to a financial counter-party;
- Convertible term contract commitments (toll or power purchase agreement), whereby a rating downgrade or other material adverse change to the asset owner triggers defined utility contract conversion rights, including a conversion to equity, or liquid security enhancement (including asset pledge); and
- Contract buy-down as a restructuring solution, whereby a utility may proactively seek to buy down an existing term contract from a generation asset in exchange for ownership or control rights to the asset.
With average gas-fired combined-cycle market values falling from approximately $600/kW on a constructed cost basis to approximately $200 to $400/kW, depending on market location and asset features, the opportunity to lower embedded capital costs and maintain supply flexibility features to respond to both uncertain market price and load conditions is growing increasingly attractive.
Of the capacity available on the market, the large majority is gas-fired, largely in the combined cycle, peaker, or cogeneration classes. In addition, a significant component of coal-fired capacity is available on the market, with price ranges reflecting competing generation sources and the environmental compliance risk reflected in the asset's emission control technology. Coal assets may present an attractive acquisition if environmental upgrade potential is high and the acquiring utility does not face significant market price exposure. A gas-fired asset will prove more attractive if the utility faces considerable load shaping obligations.
When Markets Will Recover
The current oversupply situation will not persist indefinitely. Power developers have added more than 70,000 MW of new generating capacity over the past few years. With a total U.S. installed capacity base of 786,000 MW in 1999 when the new building began, this 70,000 MW translates to a 9 percent increase in total U.S. capacity. With demand growth expectations of roughly 2 percent per year, the United States should absorb this new supply this year. An additional 50,000 to 65,000 MW under development will likely achieve commercial operation in the next couple of years, and this will extend the recovery period between one and three years. However, this assumes no retirements, normal weather, and it ignores the fact that the United States was short of capacity in many regions before the new capacity was built.
The stalled state of restructuring in many parts of the country, most notably the Southeast and Midwest, has created an environment where independent producers may only have access to an incremental market for energy. Integrated utilities with rate-based assets, acting under an obligation to serve, receive compensation for the use of their own assets and assets under contract through cost-of-service prices, set by state public service commissions to provide utility fixed cost recovery.
What is left for the independents in some regions is a very thin energy market with many independent competitors. In such markets, lack of liquidity, reliable access to the grid, and largely term contract structures make for small incremental volumes and limited market influence from independents seeking to bid wholesale prices to levels sufficient to secure fixed cost recovery.
Figure 2 illustrates that, even under conservative conditions, most regional power markets will begin to provide equity cash flows by 2006.
The retirement of older capacity could accelerate higher market prices. Retired capacity would accelerate achievement of a supply-demand balance that would support higher power prices. The conservative estimates shown above do not consider the potential for capacity retirements. Currently, 60,000 MW of coal capacity nationally could retire between 2003 and 2005 due to emissions concerns and poor operational records. These coal-fired power plants have been running at capacity factors of under 50 percent.
With demand growth and the potential for regulatory movement and capacity retirements, now is the time to develop strategies for taking control of distressed assets. There is reason to believe that well organized first movers will be in position to extract tremendous value from the distressed asset pool and have limited competition for the best assets.
During the past 18 months, spot power prices have been low relative to strengthening gas prices, creating financial difficulties for independent power producers. Fixed-cost recovery for power plants is possible only if power prices sufficiently exceed marginal fuel and variable costs of producing power. The difference between power and fuel prices, the "spark spread," typically ranges between $75 and $85/kW-year for new gas-fired power plants, the overwhelmingly predominant independent technology, to cover fixed costs and provide a 12 to 15 percent return on equity.
The regional spark spreads required to provide these returns are shown in Figure 1. No U.S. region provided equilibrium returns for new gas-fired power plants at the end of 2002, and power prices in only a few markets were high enough relative to gas prices to provide debt coverage. The inability to provide debt coverage places extreme pressure on owners and lenders, but even insufficient equity returns cause equity value deterioration, contributing to financial distress over the longer term. This, in turn, lowers asset values, setting the stage for their acquisition or refinance at lower effective capital cost recovery levels.
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