The results of annual survey of rates of return on equity authorized for major electric and natural-gas utilities-based on a sample of the retail rate cases conducted by state public utility commissions (PUCs)—show a vibrant and perhaps growing interest in traditional rate-of-return regulation.
This year's survey contains several rate-case entries that mark the first rate changes in 10 years or more. These entries show how traditional rate cases can smooth out consumer prices in the face of short-term spikes in wholesale power costs. Rate cases also allow state regulators to reconcile monopoly regulation with the radical shifts in policy that have followed from some implementation of competitive markets.
Importantly, the results reveal an ongoing debate on whether and how PUCs should tailor return on equity (ROE) determinations to take account of new, extrinsic, industry-wide risks. Such extrinsic risks conceivably could include such factors as resource adequacy, fuel-price trends, quality of service, establishment of regional markets and grid system operators, ratepayer price elasticity, or general macroeconomic ups and downs.
Consider, for example, certain recent ROE determinations from Arizona, California, and New Hampshire. They pose questions on how PUCs should respond to restructuring in the generation sector, which has led to plant divestitures, a greater reliance on wholesale purchased power to assemble a resource portfolio, and predictions of future savings in wholesale power costs, driven by competition.
A recent rate order from New England sheds new light on utility risks associated specifically with the operation of generation assets-usually considered to exceed the level of risk inherent in electric transmission and distribution activities. But in the case in question, involving Public Service Co. of New Hampshire (PSNH), the PUC came to a perhaps unexpected result. In the special rate case for gen-specific assets (decided in June, after the PUC had completed a rate review of distribution-only service), the PUC set a new, allowed gen-specific ROE of only 9.63 percent, which includes a gen-risk premium of only 21 basis points. The final rate of 9.63 percent fell below both the utility's previously approved overall ROE (11 percent on gen, transmission, and distribution, set eight years earlier), and its request as proposed in the special gen-sector case (11.34 percent). ()
Understand, however, that PSNH stands as the only electric utility in New Hampshire required by law to retain ownership of its fossil and hydro-powered generation assets. The company also enjoys added state-law protections, such as guaranteed recovery of gen-plant upgrade costs to meet environmental requirements. In practice, PSNH sells the output of its gen fleet into the wholesale market, buys back the supply needed to satisfy its own default load (to serve standard-offer ratepayers), and then credits back to default customers any net gain it earns from market transactions.
Given this unique situation, the state commission concluded that PSNH faced a relatively low risk, and set ROE for generation at the lower end of the scale indicated by various financial models. But the PUC gave weight to other factors, as well. Interest rates, it said, were near 40-year lows. It added that the gap between yields on short- and long-term Treasury bonds was decreasing, despite a recent increase in the federal funds rate. The PUC also took note of a letter published in a recognized trade journal confirming that "investors currently expect single-digit returns from utility investments."
In states where the major investor-owned electric utilities have divested themselves of a large portion of their generating assets, the utilities must rely increasingly on wholesale purchased-power contracts to serve retail customers. Also, credit-rating agencies have tended to treat those long-term purchased power obligations as the equivalent of debt capital, affecting utility financial ratios such as interest coverage, cash flow to debt, and debt to equity. The theory, known as "debt equivalence," presumes that the payments for purchased power represent a sort of substitute for interest payments that the utility otherwise would owe on bonds issued to borrow money if it chose instead to build its own generating fleet.
This theory, however, poses problems for state regulators in rate cases and ROE findings. How do adverse credit ratings affect a utility's risk profile? How do they affect a utility's supply portfolio and its long-term resource planning?
Now, in California, in a recent case setting cost of capital for the state's three major investor-owned electric utilities, a PUC has provided some answers. ()
First, the PUC agreed that in ROE determinations it can and should take account of the impacts of adverse financial ratings that stem from the debt-equivalence theory. Second, however, it advised that it would not consider such debt equivalence effects as justifying a separate inquiry on cost recovery outside of the ROE determination-i.e., in areas such as resource planning.
In particular, the PUC ruled that the utilities, as part of their annual ROE applications, should include testimony on credit rating and capital structure impacts, including mitigation recommendations, of debt equivalence on their purchased-power contracts.
Information to be provided in that regard should include:
The PUC explained that debt-equivalence risks would be assessed along with other financial, regulatory, and operational risks used in setting ROE plus use of a balanced capital structure reasonably sufficient to ensure confidence in the financial soundness of the utility.
An order from Arizona illustrates what can happen after a long time interval between rate cases, when state regulators re-appraise the value of electric restructuring, along with earlier but failed forecasts of how competition would yield efficiencies and savings in wholesale power costs.
In what it cited as the first full-blown rate review for Arizona Public Service Co. (APS) in 14 years, the commission allowed an ROE of 10.25 percent. More important, however, it OK'd an agreement whereby APS would add five newly acquired power plants into rate base, minimizing the need to rely on purchased power, in view of rising wholesale power prices in the West. ()
In a key feature of the settlement, APS agreed not to build any new plants until 2015 (subject to an exception if the need should arise to maintain reliability). At the same time, the PUC transferred five new state-of-the-art, gas-fired power plants built by the utility's parent company, Pinnacle West Energy Corp., to the utility, thereby boosting rate base by some $700 million on evidence that the plants had served ratepayers ever since the start of operations.