more to purchased power to satisfy capacity needs, but with an increase in risk. And purchased power will become even more significant if today's vertically integrated utilities spin off the generation function. Either way (spinoffs or vertical integration), utilities must address this added risk: through fair compensation, and by correctly assessing the true cost of supply alternatives in resource planning.1
When utilities sign long-term purchased-power contracts that include a fixed-cost component, they incur financial, regulatory, market, and supply risks, as well as the risk associated with a declining rate base. Nevertheless, regulators often do not augment return on equity to compensate. This failure imposes consequences. Over the past few years, numerous companies have had bond ratings lowered, or not increased, due to purchased-power obligations.
Financial theory often breaks risk down into two components (em business risk and financial risk. Business risk denotes the uncertainty associated with the level of operating earnings. Financial risk marks the additional risk a company takes on by assuming fixed-cost obligations. For example, as more debt is added to the capital structure, a company faces more fixed charges (i.e., debt payments); bondholders and stockholders both run the risk that operating revenues will fail to cover expenses and return on capital. Thus, as the share of debt rises in capital structure, bondholders and stockholders will demand a higher return to compensate for the higher leverage and financial risk.
generally contain two forms of charges (em energy charges (a variable cost) and capacity charges (in take-or-pay contracts, a fixed cost). Even though purchased-power obligations are placed off the balance sheet, they nonetheless represent fixed obligations that impose a financial effect similar to incurring an equivalent amount of debt. That is why some rating agencies have referred to purchased-power fixed charges
as "debt equivalents." Thus, purchased-power commitments lead the investment community to regard utilities as having more leverage than shown on their balance sheets.2
Two other aspects of these fixed payments leave a utility financially worse off than if it had constructed its own plant.
First, a utility that constructs its own plant recoups a return on investment (interest charges and return on equity, along with associated taxes), plus a return of investment (depreciation). Of these amounts, only the interest payments represent a fixed cash outlay. However, a utility's capacity payments under a purchased-power contract cover the interest, return on equity, taxes, and depreciation of the selling plant's owners, and the entire amount of the payment is fixed. Therefore, a larger fixed payment is associated with a purchased-power contract than with a comparably sized, self-built plant.
Second, a utility finances plant construction in part with fixed-cost capital (i.e., debt) and in part with equity, the return for which is taxable. Under regulation, it collects funds (return on equity and taxes) to help cover the fixed costs of the debt for the plant in question. However, most jurisdictions allow no return on equity, and no tax, associated with purchased-power payments, so that coverage on such payments is effectively reduced to 1.0 times. Other
things being equal, coverage
problems are more likely under a purchased-power regime.3
Regulators may delay or deny recovery of purchased-power costs. They may decide that the utility will not need the power down the road, or that the resource is "too expensive."
With regulatory review an ever-present risk, purchased power means "heads you win, tails I lose." Risk mounts without reward. If regulators find all aspects of a contract acceptable, utilities receive only one-for-one recovery of expenses; if regulators find fault with the purchased-power arrangement, utilities can receive a penalty or disallowance. The risk/ return equation has become skewed.
Supply risk from purchased power takes at least three forms: 1) The plant may fail to come on line; 2) once on line, the plant may prove unreliable; or 3) third-party resources may lack diversity, relying too much on a single fuel.
If contracted purchased power fails to materialize, a utility may have to construct a plant itself on an accelerated (and costly) basis or face the market in a poor ("must buy") bargaining position. Under today's regulation, a utility still retains the obligation to serve; an independent power producer (IPP) does not. As for reliability, most IPP plants are new and have yet to establish a track record for long-term performance.
Much IPP generation burns natural gas. If utilities continue to increase their purchases, and such power remains predominantly gas-fired, the fuel supply will lose diversity. History has shown the danger of relying too much on one fuel, such as natural gas.4 A gas shortage could cause a severe electric capacity shortage given a confluence of two events: 1) customers suddenly wish to return to full utility service due to a curtailment in their own gas-fired supply of power, and 2) gas-fired IPPs are unable to fulfill their contracts and deliver power to the utility.
SOME POSSIBLE SOLUTIONS
Despite the asymmetric nature of risk inherent in purchased-power contracts, utilities and regulators nevertheless can choose among several options to deal with the problem.5
Raising the common equity ratio, either in fact or through regulatory imputation, would mitigate/compensate for the increased financial risk of purchased-power commitments (see table on next page). The table shows base-case scenarios for a company both before and after a purchased-power commitment. Before the commitment (columns 1 and 2), the company carries a 55-percent debt ratio and a 45-percent equity ratio. After the commitment (columns 3 and 4), the market perceives the equity ratio as only 40.91 percent. Selling sufficient new common equity (columns 5 and 6) can return the market-perceived common equity ratio to 45 percent.6 Imputing a higher common equity ratio for ratemaking (columns 7 and 8) would also return the market-perceived equity ratio to the pre-purchase level of 45 percent.
In the alternative, the allowed return on equity could be raised to compensate for increased risk flowing from purchased-power commitments. To adjust the return on equity upward to account for increased leverage caused by the debt equivalence of purchased-power commitments: 1) use classic capital structure/cost of equity theory propounded by Miller and Modigliani; 2) employ a technique of unleveraging and releveraging beta, as suggested by Hamada; or 3) measure the incremental
increase in cost of equity caused by taking on purchased-power commitments.
These adjustments can be applied to either the equity ratio or cost rate of equity that will be used to determine the allowed return on the equity portion of rate base. Such calculations may be adequate now when the rate bases of utilities generally are large relative to purchased-power commitments. However, if
purchased-power commitments become relatively large and rate base relatively small, any adequate return to compensate for risk might have to be allowed on the value of the purchased-power commitment itself, rather than on rate base.7
One final approach to compensating a company for purchased-power risk would be some type of incentive mechanism. For example, if a purchased-power contract results in savings over the life of the contract, the utility should be allowed to share some percentage of these savings. Such a mechanism would provide some compensation to the utility in question, and would also give the utility an incentive to save as much money as possible when making purchased-power arrangements. t
Robert Rosenberg, principal of Benrose Economic Consultants in New York City, has more than 25 years' experience in regulatory economics. He works in areas as diverse as rate of return, financial integrity, royalties, and economic effects of EMF.
The Declining Rate Base
If utilities buy more power outside, and slow construction of new plants, depreciation on existing plant may come to exceed new capital investment, causing rate base decline:
. Earnings will fall if tied to rate base.
. The utility will become smaller and riskier.
. Deferred taxes will reverse and suddenly come due, as the utility pays more in cash taxes than it collects through rates.
1. The fact that a highly-leveraged IPP is able to bid what seems to be a low price to provide purchased power does not take into account the fact that the IPP effectively borrows the electric utility's credit strength in being able to leverage itself so highly. That is certainly part of the overall cost to the utility for accepting the contract and should not be ignored.
2. Rating agencies now adjust capital structure ratios and interest coverage ratios to reflect the debt equivalence of fixed payments associated with purchased-power contracts.
3. Even under the several alternative purchased-power risk-mitigation scenarios discussed later in this article, pretax interest coverage would still decline from the pre-purchased power level. The calculations demonstrating this are not presented here in order to simplify the analysis.
4. See, for example, "Electric Reliability: How PJM Tripped on Gas-Fired Plants," by John Hanger, PUBLIC UTILITIES FORTNIGHTLY, May 1, 1995, p. 27.
5. The following discussion covers only increased financial risk of purchased power and in no way covers any increased business risk that may result.
6. Selling new common equity may not be feasible at times due to company-specific or general market conditions. However, even if new equity cannot be sold over the short run, this scenario can be regarded as reflecting a utility's long-run policy of increasing the equity ratio to counteract purchased-power risk.
7. A Mississippi law now allows for the possibility of earning a return on purchased-power costs.
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