Efforts to make generation competitive have induced several electric utilities to sell their power plants. Some sales are voluntary. Some are forced by rules mandating functional segregation from transmission and distribution. Of those sales announced or completed, most have involved high-cost utilities, and all have garnered at least book value, suggesting an attempt by sellers to deal with stranded costs.
Why then, are buyers willing to pay more than book value? They must believe they can improve on cash flows - either by raising revenues, trimming costs, or both. But such expectations lie open to scrutiny.
For one thing, price deregulation does not eliminate regulation.
I started my consulting career with the management consulting firm that remained after Sam Insull's Middle West Utilities operating companies were spun off in response to the 1935 Public Utility Holding Company Act. Insull supported regulation early on, because he knew it would stifle competition. Today, electric utilities deciding to retain the wires business are opting for continued price regulation, but some are also opting to participate in the market for unregulated generation. This mixture of regulation and competition will prove unstable and will invite efforts to extend government oversight beyond the regulated business. Note, for example, how the California Independent System Operator has mandated that plants designated as "must-run" by the California Public Utilities Commission must sell into the Power Exchange at prices based on costs approved in regulatory proceedings.
On the other hand, whatever deregulation does take place will only hasten the onset of new technologies - which could make any asset a white elephant.
Regulated businesses can control the introduction of new technology, but competitive firms cannot. Consider the concept of central station generation. It came about through the development of high-voltage transmission lines, but further developments are likely to eliminate it. That process is already in place, as is evident from large customers installing peak-shaving facilities and from expansion of distributed generation to smaller customers through installation of combustion turbines, fuel cells and solar units.
Of course, for the buyer, special circumstances may govern the relationship between price and book value. The buyer may assume purchased power contracts, fuel supply agreements, power supply commitments or operation and maintenance contracts - any of which could be above or below market. The plant may carry environmental or decommissioning obligations associated with retirement. Also, depreciation deferral may have inflated book values.
Nevertheless, any buyer seeking to boost revenues must either charge higher prices or increase product volume. Higher prices would be detrimental to consumers and could attract the attention of regulators. Higher volume would require changing the way the generating units are operated or require site expansion or unit replacement.
In fact, if opportunities to improve operating cash flows are as limited as I believe, then the announced or completed sales suggest that site expansion, through the addition of new units or replacement or refurbishment of existing units, marks an important consideration in the minds of would-be plant purchasers. If this assessment is correct, then purchasers are more interested in buying sites than in buying equipment.
Roadblocks to Profit
Can the new buyers boost revenues or cut costs? The change in ownership might influence a number of cost factors, such as operation and maintenance, fuel, depreciation, taxes, accounting rules and financing. However, an acquisition price higher than book value might itself increase some costs.
O&M. It may be possible to decrease operation and maintenance expenses, but many utilities have already made such reductions to become more competitive. Skimping on maintenance costs implies accepting risk for availability and reliability, as demonstrated by the unfortunate experiences of some nuclear plant owners in attempting to minimize O&M costs.
I know of one small municipal electric utility in the Midwest, operating without interconnections. It suffered a summer storm that drained a reservoir used to supply the city's water and cool its generating station. Customers found themselves without water or electricity for about a week. An electric outage of only a few hours a year later prompted customers to demand that the electric operation be sold, which was done.
Another consideration when decreasing maintenance expenses is that mortgage bond indentures often require periodic certification that the underlying assets are being maintained at a level sufficient to generate the income needed to retire the debt.
FUEL. Potential savings in fuel costs lie in two areas: heat rate improvements and lower unit prices. However, heat rate improvements are no more available to a new owner than to the prior owner. And utilities are large fuel users, so a new owner may not be able to purchase fuel any cheaper. In fact, some plant sale contracts have committed the utility to continue to supply the fuel.
Of course, new owners purchasing high volumes of fuel may enjoy market power, but they will have to watch out for regulators. A buyer might benefit by playing spot and long-term markets against each other, but will it outperform the previous owner? The same might be said of any potential opportunities for fuel conversion. Why wasn't it done before?
TAXES. Since property taxes tend to run higher for utilities than for other businesses, they should fall under deregulation. Taxing authorities can be expected to oppose efforts to roll back property taxes, however, so a new owner might find little to gain.
Income taxes will follow income, but will be influenced by financing costs. Regulated firms are generally well regarded by investors, and so can borrow at low cost. However, investors tend to look down on entities with nuclear stations, and the magnitude of stranded costs being discussed suggests that investors may have under-estimated the amount of risk imposed by regulation. While a new owner might be interested in financing with a higher portion of debt, the financial market may view the level of risk as requiring less debt and early maturity.
DEPRECIATION. So far only two of the many plant sales have involved nuclear units. In fact, many nuclear plant owners have already taken steps to reduce their costs by accelerating the rate at which they record depreciation or amortize related regulatory assets of these efforts to accelerate cost recovery, none have involved tariff increases. Most have involved tariff decreases, through accepting lower rates of return or passing on to current customers the savings expected from downsizing, mergers and smaller rate bases expected in the future. In one case, the resulting low rate of return was cited as one reason for a voluntary decision to sell generating facilities.
If deregulation strips regulators of jurisdiction over depreciation, owners of deregulated generating stations would gain the option of switching from the "group" to "item" concept of depreciation. Either way, the costs currently recorded as depreciation are likely to increase.
Recorded costs would increase under the group concept as a result of the need to eliminate any existing deferral of recording depreciation that is a common consequence of regulation. Such deferral results from generating units with depreciable lives longer than expected by the owner, from backloaded depreciation rate calculation methods, and from inadequate allowances for terminal demolition costs. Recorded costs would increase under the item concept beyond eliminating any regulatory deferrals, because component replacements previously capitalized would now be expensed and depreciable lives likely would be decreased to minimize tax and book depreciation differences and the potential for recording losses due to underdepreciation.
Another depreciation consideration is that the Financial Accounting Standards Board is currently considering a new accounting standard, the first exposure draft of which would eliminate depreciation treatment and require backloading the recording of terminal demolition costs. How the deferrals under the proposed accounting standard compare with the regulatory depreciation deferrals of the prior owner, if any, will determine whether the demolition costs recorded by the new owner will be higher or lower than by the prior owner. Further, under the proposed standard, a significant portion of the terminal costs would be recorded after the facility ceases to be productive.
Does Plant Type Matter?
Specific comments are warranted with respect to peaking plants, nuclear units, and hydroelectric projects.
PEAKING CAPACITY. About 15 to 20 percent of the U.S. utility electric generating capacity is comprised of peaking units that are operated infrequently. A significant portion of this capacity is made up of steam-driven units that were originally installed to perform a base-load role. While the book value of such units should be quite low, it is the high incremental out-of-pocket cost that keeps them from operating. Therefore, these units may have little or no value to a new owner and are more likely to be replaced than to be refurbished sufficiently to change their mode of operation.
A change of ownership does not change the timing of customer demand for service, and so will not decrease the need for some generating units to perform a peaking function. However, peak shaving through distributed generation may reduce this need to some degree. This situation suggests that new owners of steam units currently serving a peaking function will quickly replace them with combustion turbines.
NUCLEAR. One hears of declarations of intent to sell nuclear units, but only two transactions had been disclosed by the parties as of the end of July.
Eastern Utilities Associates announced an agreement to sell its 2.9 percent share of Seabrook. GPU Inc. announced an agreement to sell Three Mile Island unit one. The EUA announcement did not disclose book value, but the selling price of $95 per kilowatt suggests a price under book value. TMI was sold at 17 percent of book value ($127/kW).
Seller retention of the decommissioning obligation, or up-front funding as for the EUA sale, may be necessary for sales of nuclear units to take place. However, while current regulatory commissioners may agree that the seller's customers should pay for decommissioning, there is always a risk that future commissioners will decide differently. The Nuclear Regulatory Commission allows regulated utilities to fund decommissioning costs over the operating life of the facility, but requires up-front funding by nonregulated entities, which may limit the market for nuclear units.
What prospects do utilities have to keep operating their nuclear plants?
No nuclear unit has yet lived as long as its license term. In fact, industry experience to date indicates life spans about five years shorter than license terms. Early retirement is not surprising because nuclear units require costly component replacements and upgrades that become less feasible as the time for license termination draws near. However, the NRC has issued rules and regulatory guidance that would allow license renewal for up to 20 years beyond the termination dates of original licenses, so there is now an alternative to retirement prior to termination of the original operating license. Baltimore Gas & Electric Co. and Duke Energy recently became the first utilities to file applications for license renewal. If license renewal applications become as political as applications for operating licenses became, renewal will quickly disappear as an option.
HYDROPOWER. Some hydraulic stations have been sold together with steam stations, but their purchase prices have not been disclosed separately. Now, however, Niagara Mohawk Power Corp. and Pacific Gas & Electric Co. have announced their intent to sell hydro stations, so values of such facilities soon will be a matter of public record.
Hydro stations have low operation and maintenance costs and no fuel costs, but have higher construction costs than steam stations and some nuclear stations. However, long operating life spans mitigate high construction costs to some degree. Low operating costs will make hydro-stations attractive to new owners, and high capital costs are likely to assure that new owners are buying the equipment and not the site for redevelopment. Further reasons for lack of site redevelopment are the interest of environmentalists to return rivers to their pristine state and the policy of the Federal Energy Regulatory Commission to consider dam removal as an alternative to project relicensing. Purchasers should recognize that removal costs may be higher than the original cost and that maintenance of a reservoir is forever. It is not yet clear whether sales agreements for hydraulic stations will need to treat decommissioning obligations like the obligations for nuclear stations.
Independent consultant John S. Ferguson is a former principal of Deloitte & Touche LLP and a frequent contributor to Public Utilities Fortnightly.
* While it is true that some individual units have sold for less than book value, that has not occurred for any single group of stations. For example, Pacific Gas & Electric sold its Morro Bay, Moss Landing and Oakland stations as a group at more than their combined book value, but Morro Bay and Oakland units were each priced at less than their individual book values.
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