The results of Public Utilities Fortnightly’s annual survey of rates of return on equity (ROE) authorized for major electric and natural-gas utilities broadly show a continuing decline in the level of debate over issues specific to restructuring of the electric market. The survey also reveals a subtle shift back to investor requirements and overall business risks faced by regulated energy companies.
For example, in a gas rate case decided in Nevada, regulators rejected an ROE “risk adder” proposed by a natural-gas local distribution company and reminded the utility that hard evidence such as credit ratings and regulatory rulings are what makes the difference in a rate-case setting.
The Illinois Commerce Commission reviewed the underpinnings of the traditional ROE process when it rejected a proposal by a party to a major electric rate case to switch to a completely new approach, purportedly based on direct evidence from the investment-banking community. As it turned out, the so-called “investment-bank analysis” produced an ROE estimate much lower than any produced by the standard financial models normally relied upon in rate cases. The commission concluded it had no way to know what assumptions investment bankers use when putting a value on utility stocks, or whether such an estimate might satisfy the legal requirement for just-and-reasonable rates in a regulated market.
In its most recent natural-gas rate case, Sierra Pacific Power Co. asked the Nevada Public Utilities Commission (PUC) to approve a risk-premium adder when estimating the ROE investors would demand before investing in the company. Sierra Pacific argued that it faced an unusually risky position in the near term due to factors such as rapid customer growth and projected increases in capital expenditures. The PUC said the utility had failed to put forth any evidence that the premium adder is necessary for capital attraction. More to the point, the PUC noted that the company could not explain why it has been able to improve its credit rating from a “B” to a “BB” bond rating since the last rate case, when the current ROE of 10.25 percent did not include a risk-premium adder. Finally, the commission pointed to its own recent actions that would reduce risk perceived by investors in the near term, including:
1) Commission statements and orders that indicate the PUC is satisfied with the company’s procurement strategy policies;
2) Regulatory changes that cause an annual review by the PUC of Sierra Pacific’s annual energy supply plan, which informs the commission of short-term purchase plans and number trends, thus decreasing the likelihood of future disallowances;
3) Regulatory changes to allow utilities to file annually for two energy cost adjustments if necessary, which is helpful in avoiding large deferred energy balances; and
4) Regulatory changes and commission orders that allow for an equity premium adjustment to Sierra Pacific’s ROE for construction projects that are deemed critical facilities. Re Sierra Pacific Power Co., Docket Nos. 05-1005 et al., 248 PUR4th 364, April 27, 2006 (Nev. P.U.C.)
In a major rate case involving electric delivery services provided by Commonwealth Edison Co. (ComEd), a coalition of groups representing small consumers looked to recent valuations of utility assets conducted by investment banks to support a new approach to estimating a rate of return that would attract investors to utility stocks. (The recently terminated plan for a merger of ComEd parent, Exelon, and Public Service Enterprise Group [PSEG], a New Jersey company, provided current market data and an opening to pitch the novel approach.) Using this new method, the consumer groups suggested that investors would favor investment in ComEd so long as a 7.75 percent equity allowance was included in rates. The alliance of consumer groups had estimated ComEd’s cost of equity by inference from the weighted average cost of capital (WACC) calculated by Morgan Stanley for the merger of Exelon and PSEG. All other parties to the Illinois Commerce Commission (ICC) case used complex financial models to gauge ROE requirements and came up with much higher estimates, including the utility’s offered 11 percent, the 10.19 percent presented by the commission staff, and 9.9 percent favored by a large industrial users group.
Predictably, ComEd responded that the new method presented by consumer groups could not possibly be reasonable because the 7.75 percent ROE it produced is more than 100 basis points below any ROE recently approved in the United States.
The consumer groups explained that because the cost of common equity is not a directly observable number, regulatory commissions have had to rely on subjective models, such as the capital-asset pricing model and the discounted cash flow model, to estimate a utility’s cost of common equity. The consumer parties argued that recent merger activity in the electric industry could provide more direct evidence on cost of equity, and a unique opportunity to move away from the complex financial models. With this in mind, the groups hired an expert to recommend a cost of common equity based on a review of electric utility stock valuations conducted by three leading investment banks—Morgan Stanley, JP Morgan, and Lehman Brothers—for the merger between Exelon and PSEG. According to the groups, the valuations done by the three investment banks are a far more reliable indicator of investor needs than the subjective models used to bridge evidentiary gaps “that arise because the level of return required to induce real investors to provide capital for the firm is not directly observable.”
The ICC rejected the new approach, finding that while the consumers had portrayed their method as more objective than standard models, it was impossible to know what assumptions were made by the investment bankers, and whether the result was appropriate in a regulated setting. The commission noted that the expert had relied on WACC figures published by the investment firms as the basis for the estimates. To back out the cost of equity from the investment bankers’ WACC estimates, the expert first had to make numerous assumptions, the PUC found.
The commission said it could not determine if the investment bankers used the same approach when determining cost of debt, what mix of debt maturities they used, or if they included short-term debt. Further, it is unclear whether the Morgan Stanley analysis was for Commonwealth Edison and PECO, a Pennsylvania-based affiliate, separately, or for the proposed combined entity. It also is not known if the investment bankers used the same capital structure or made the same assumptions regarding the treatment of transitional funding instruments, the ICC added. Re Commonwealth Edison Co., No. 05-0597, 250 PUR 4th 161, July 26, 2006 (Ill.C.C.).
* Settlement agreement. No ROE figure stated.
1. ROE figure shown includes a 30 basis-point upward adjustment to account for LDC’s higher risk when compared to financial study proxy group.
2. Adopted ROE set below the normally accepted mid-point range to reflect finding that LCD had been deficient in accounting and record keeping practices, and had exhibited a pattern of inadequate customer service.
3. Order adopting rate-making cost of capital for major investor-owned energy utilities.
4. Approved overall rate of return 5 basis points higher than last authorized rate. Produces only nominal change in revenue requirement.
5. Although allowed ROE is 20 basis points higher than prior year’s award, rate reduction results from lower approved figures for cost of debt and preferred stock.
6. Revenue sharing agreement settlement. Existing rates remain in place. Retail base-rate revenues between specified threshold amounts will be shared 2/3 to ratepayers and 1/3 to shareholders. No ROE specified in revenue-sharing settlement
7. Figure shown is current ROE for recovery clause calculations and other non-base-rate purposes.
8. Stipulated overall rate of return of 8.1%. No ROE given.
9. Delivery service only.
10. Final figure per order on rehearing issued 05/28/06. Initial order included an increase of $45.6 million.
11. Settlement agreement. No ROE figure provided. Overall rate of return listed as 8.879%.
12. Settlement agreement includes ROE as shown.
13. Figure shown includes adjustment for initiation of fuel adjustment charge rate.
14. Approved settlement provides that $28.106 million in environmental surcharge costs will be removed from adjustment clause filing and incorporated into base rates.
15. Order on periodic earnings review under existing rate stabilization plan. Threshold for earnings sharing lowered from current ROE of 12.25% to 11.25%.
16. Commission finds stranded cost recovery complete. Figure shown allows full recovery of production fixed costs on a going-forward basis.
17. Figure shown is Phase 1 grant. Phase 2 grant totaling an additional $114.9 million revenue requirement effective 1/1/07.
18. Commission rejects proposed risk-premium adder as unwarranted given LDC’s improved credit rating and recent regulatory actions limiting risk such as preapproval of energy supply plans and ROE premiums for large construction projects.
19. Delivery service rates.
20. Revenue award includes credit of $1.4 million in allegedly unreasonable gas commodity costs recovered from ratepayers in 2005-2006 heating season.
21. Per settlement proposal. Commission finds revenue figure reflects amount the LDC requires to operate and maintain its gas distribution system.
22. Figure as listed in approved settlement agreement.
23. In July 14, 2005, order for notice and hearing the commission consolidated utility’s rate-case filing and application for performance-based rate plan. Utility may decline commission-approved performance plans, in which case rates may be reset based on cost-of-service data.
24. Order approving performance-base rate plan. Commission rejects proposal to dismiss general rate filings and approves revenue requirement findings as shown to be used in event utility rejects plan.
25. Financial data indicated the need for a $393.9 million increase, but WEPCO only requested an increase of $256.4 million based on the recovery of: $67.5 million in costs related to transmission charges; $70.1/million related to reliability investments; $6 million in costs related to renewable sources of energy; $93.4 million in additional fuel costs; and $19.4 million related to Midwest Independent Transmission System Operator additional costs.