David Hayward, R. W. Beck
The so-called “distressed assets crisis” related to the electric generation business has gained notoriety recently. Some experts estimate that, in the U.S., the industry has between 100,000 to 136,100 MW of excess generating capacity. In addition, related to these assets, between $40-90 billion in debt is due by 2006. The primary sellers of these assets include NRG, Mirant, PG&E National Energy Group, and others (e.g., banks, insurance companies, etc.).
Potential buyers include investor-owned utilities (IOUs), generation and transmission cooperatives, unregulated arms of utilities with strong balance sheets and private equity companies such as Berkshire Hathaway and AIG—the latter is generally less concerned with the location of assets.
At least three general options exist for asset owners: Sell the asset at auction at distressed prices, mothball the units and wait for better opportunities, or hire a company to operate the unit (assuming that the market price for electricity will support a price in excess of the variable cost of operation). In many cases, the operators of the assets are subsidiaries of IOUs and may even take an equity position in the plant.
What are the regulatory implications of IOUs purchasing the distressed assets (i.e., the auction option)? Are they possibly the same assets that were divested when “deregulation” in the electric utility industry first started?
A look back
The current downturn started when the National Energy Policy Report 2001 overestimated the need for additional capacity in the U.S. over the next decade. The resulting excess capacity coupled with “turbinemania” (i.e., the introduction of relatively low-cost, high-efficiency gas turbine engines), and a slowing U.S. economy are the primary causes of the current glut.
In late 2002, the merchant power sector went out of favor due to a variety of factors: the Enron scandal, accounting problems associated with energy trading misconduct, lack of markets, falling electricity prices, high debt and the falling credit rating for the entire sector.
The economics of the merchant power business in recent years have been characterized by excess supply in the wholesale power markets, high natural gas prices and, in some cases, operation of less efficient generating units. The result has been the need for many companies to refinance debt and/or sell assets. For example, PG&E National Energy Group recently turned over some of its assets to various lenders (e.g., Citibank).
Determining the appropriate value of these distressed assets can be challenging. Experts in the field generally use one or some combination of three approaches. These approaches include the market, cost and income. The results from these three approaches can produce significantly different valuations.
The market approach has the best intuitive appeal since it is difficult to argue with the price of an asset determined by unconstrained buyers and sellers (i.e., the “willing buyer” and “willing seller” assumption used in the valuation jargon).
The problem is finding truly comparable sales since the value of a plant can be significantly affected by: the supply and demand balance of electricity in a region, with several regions expected to be overbuilt for much of the next 10 years; possible high voltage electric transmission constraints; “must-run units”; and “good” and “bad” assets, with good assets having existing firm long-term contracts and solid operational characteristics.
The cost approach to valuation looks at the original cost, reproduction cost, or replacement cost (less accumulated depreciation) of an asset. Original cost (less depreciation) is the most frequent method used for determining the rate base of regulated assets for a utility.
The income approach analyzes the stream of income for a project over a forecast period. Various applications of the income approach include capitalization of earnings, or discounted cash flow (DCF) analyses. During the period when regulated electric utilities were divesting their generating assets, the non-regulated merchant power producers typically used a cash flow approach to value the assets. The DCF model, relying on the use of free cash flows, provides superior results as compared to the cost and market approaches since it explicitly incorporates the timing and amount of future revenues, investments, depreciation, amortization and deferred income taxes—and all of these factors can have a significant impact on a generating plant’s valuation.
Generally, regulators do not allow utilities to recover prices paid above book value from customers. This premium or differential is called the “acquisition adjustment.”
To the extent that regulated IOUs are the potential purchasers of these distressed assets, regulators of the IOUs have a particularly important challenge: They must provide a set of incentives for the utility to make the right purchase decision.
If the regulatory case law in a state constrains the utility to purchase the previously regulated plant at or below book value (or without recovery of the acquisition adjustment from the ratepayers), this constraint may limit the utility’s ability to effectively compete with merchant power producers that may value the plant differently (e.g., using the income approach) and as part of a diversified portfolio. To date, there are few, if any, examples of IOUs reacquiring previously divested generation assets.
To understand these regulatory implications consider California. If the California power crisis taught us anything, the primary lesson was the enormous cost of making an incorrect economic choice. During the early phases of deregulation, at least in California, there was such a push for the IOUs to divest fossil-fuel assets that perhaps insufficient attention was spent on determining the true value of the assets. For example, the result was that, in some cases, the net proceeds from the sales to the ratepayers were equivalent to approximately three days of power costs incurred by the State of California.
Today’s power markets are changing the way generation assets are valued. Not only do future cash flows contribute to the overall value of a plant, but additional value can be derived from a plant’s option to run, switch to another type of fuel or shut down. The value of this “optionality” is captured in some of the valuation models used today.
Just as using the original cost (less depreciation) method of valuing a generating plant was not necessarily a meaningful barometer of value when the plants were divested (in some cases at prices two-to-three times book value), it is not all that meaningful in terms of acquisition decisions.
For instance, if a utility had an opportunity to reacquire the same plant it previously divested at some multiple of its original book value, would this be a good economic decision? On the surface, it’s impossible to say. A DCF approach could provide far more insights as to the plant’s true value; however, regulators have historically focused on book value as producing some magical number.
Perhaps regulators should consider allowing the utility to recover a portion of the acquisition adjustment associated with reacquired plants, or a premium return on the purchase of other distressed generating assets. Clearly, given the historical earnings volatility of companies in the merchant power industry, in some cases a premium return on generating assets could be justified. To put this in perspective, the Federal Energy Regulatory Commission (FERC) is considering allowing a premium return on certain electric transmission assets.
Maybe state public service commissions should employ some form of “incentive-based regulation” to reward or penalize utilities for decisions to purchase the distressed generating assets now on the market. Several examples exist throughout the U.S. related to incentives for electric utilities to operate generating plants efficiently. No inherent reason exists to preclude a utility’s investment in distressed generating assets from the scope of incentive regulation.
One possibility would be to cap the value of the asset at Replacement Cost Less Depreciation (RCLD), and allow the IOU to earn a premium return for each 10 percent increment the plant is purchased below RCLD.
It is important to recall that regulatory uncertainty (e.g., the disallowance of investment in generating assets and the authorized rates of return on utility rate base) was one of the key considerations in IOUs not investing in generating facilities in service territories. The old “obligation to serve” by the IOUs was replaced by no commitment or obligation to serve on behalf of the merchant power producers. One can question if this shifting of responsibility was truly in the “public interest.” Thus, it’s time for regulators to consider fresh solutions to the problems in the electric generation business. The cost of being wrong again is simply too great.
Hayward is an executive consultant with R. W. Beck Inc., and the primary author of “Valuing an Electric Utility: Theory and Application.” He can be reached by e-mail at email@example.com or 858-485-4674.