Economic uncertainties raise doubts about utility returns.
Recent shocking and unprecedented news in financial markets brings to mind several questions about utility rate cases and authorized returns. Given that utility regulators rely on financial models when seeking to determine the cost of capital for a utility, one might ask what effect stock prices and interest rates will have on the process. Will regulators feel a need to consider broader economic effects when engaging in a process that is often closely watched by the investment community?
In this time of economic uncertainty, utility investors are reminded that authorized return on equity (ROE) allowances aren’t actual earnings, but rather the rates utilities and regulators use to determine how much money consumers must pay to make it possible for the utility to earn a reasonable profit and to attract investors in the future. As such, the award is not a guarantee. To earn the ROE set by a commission, the utility must keep future expenses and sales at or near the levels as during a 12-month proxy period known as the “test year.”
In extraordinary times like these, regulators should expect some extraordinary testimony from the financial experts who appear as witnesses in rate cases.
The Ratemaking Formula
Reported here are results of Fortnightly’s annual survey of utility rate cases. The survey, which reports the statistical results of traditional rate proceedings, provides a sample of major retail electric and natural gas rate cases conducted by state regulators across the nation. (And this year, for comparison, we included several Ontario rate cases.)
When setting rates, regulators gather information about what it will cost the utility to run the company, including operating expense, taxes and depreciation, short and long-term borrowing, plus the fair return on investment. To arrive at an amount of money to be collected from ratepayers for the return component of rates, the value of the company’s property, or rate base, is calculated and the ROE rate is applied to that figure. The resulting number of dollars is then added to the cost-of-service ratemaking formula to arrive at a total revenue requirement for the utility.
Given this, it’s easy to understand why the ROE part of a rate case often is the most contentious. First, while expenses and other costs might be determined with some level of certainty, the amount of profit that’s considered “fair” certainly is subject to debate.
Additionally, the second part of the issue—what level of return is necessary to attract investment in the company and provide incentives for managers to make business decisions that benefit consumers—also is a question tailor-made for debate, and for analysis by financial consultants and attorneys.
In a case reported in this year’s ROE survey, the Wisconsin Public Service Commission (PSC) discussed the distinction between the “bare-bones” cost of capital, as revealed by statistical models, and the appropriate ROE award for ratemaking purposes. The PSC explained one view: The cost of equity represents the target for the return on equity. According to this perspective, financial-model results are the central focus, and absent extraordinary circumstances, the regulator should set the ROE at its best estimate of the utility’s cost of equity.
An opposing view also was offered by the PSC: The cost of equity is just one of several factors that direct a regulatory body toward the proper ROE. In this view, during normal economic times, the financial models provide estimates as to the minimum acceptable return, and not necessarily the fair return. The fair return, under this method, typically lies above the cost of equity.
The Wisconsin PSC chose the latter view, explaining that the cost of equity represents the starting point in the ROE analysis, and in most cases does not represent the target rate of return for ratemaking. The PSC said setting the return on equity at the cost of equity, by definition, is a minimalist policy that would allow the utility barely to compete for capital. [See Re Northern States Power Co., Wisconsin, 264 PUR4th 236, No. 4220-UR-115, Jan. 8, 2008 (Wis. P.S.C.).]
Stock Prices and Interest Rates
Stock prices and interest rates are fundamental inputs in models used in setting ROE awards. Interest rates frequently are cited as a benchmark. The so-called “risk-free rate” readily is observable in the market for government securities. The base rate is identified for the test period under review and a premium above that amount is chosen that represents the increase necessary to cover additional risk associated with stocks and to attract utility stock investors. If rates for government securities are low, many would argue that ROE awards should follow.
Another example of how changes in interest rates might affect ROE awards is found in a recent decision by the California Public Utilities Commission (PUC). In that case, the PUC adopted a new, multi-year cost-of-capital mechanism (CCM) for the major California energy utilities. Under the new plan, the costs of capital used in setting rates for the utility companies—i.e., costs for long-term debt, preferred stock and common equity—will be set every three years in a full cost-of-capital proceeding. However, changes in interest rates that occur outside of a 100-basis point deadband under a 12-month measurement period would trigger adjustments to the capital cost rates of the utilities. [See Re Southern California Edison Co., 265 PUR 4th 161, D. 08-05-035, (Cal. P.U.C. 2008).]
As for stock prices, a review of this year’s rate cases shows the discounted-cash-flow (DCF) method remains the gold standard for financial modeling of utility cost of capital. (Other methods that directly assess the cost of risk-free investments also are used.) The DCF method uses as input the stock prices and dividend payments of companies with comparable risk. The most recent stock price is the one used when calculating dividend yield and growth rates under the DCF. As described in Dr. Roger Morin’s text on utility cost of capital, The New Regulatory Finance:
Conceptually, the stock price to employ is the current price of the security at the time of estimating the cost of equity, rather than some historical high-low or weighted average stock price over an arbitrary historical time period. The reason is that the analyst is attempting to determine a utility’s cost of equity in the future, and since current stock prices provide a better indication of expected future prices than any other price …. [t]he most relevant stock price is the most recent one…. Use of any other price violates market efficiency.
In rate cases to come over the next year, the drop in stock prices will have a major effect on the debate. It remains to be seen how the experts and the commissions will explain the role of the models in the process and the hard decisions that must be made to keep utilities financially sound.
1. Utility operates under a rate stabilization and equalization (RSE) plan – an alternative rate-making mechanism that provides for periodic automatic adjustments to maintain ROE within a specified range. ROE figure shown is midpoint of approved range.
2. Order renews existing RSE approved by Order issued 6/10/2002 for period of seven years ending on Dec. 31, 2014.
3. Includes phase-down of existing cap on ratio of common equity to average capitalization to 57% by Dec. 31, 2008 and to 55% by Dec. 31, 2009.
4. Produces overall rate of return on “fair value” rate base of 7.03%.
5. Settlement stated ROE; ROE figure reflects downward adjustment for reduced risk associated with billing determinant adjustment tariff.
6. Order adopting ratemaking cost of capital for major investor-owned energy utilities.
7. By subsequent order commission adopts a multi-year cost-of-capital mechanism (CCM) for major utilities. Under CCM, utilities will file applications every third year beginning in April 2010. Changes in interest rates outside of a 100-basis point dead band would trigger off-year adjustments. See Re Southern California Edison Co., 265 PUR4th 161 (Cal.P.U.C.2008).
8. Order determing utility earned $15.5 million in excess of allowed ROE.
9. Allowed ROE approved March 14, 2007 rate-case decision.
10. Department finds 10.1% ROE reasonable for current earnings review.
11. No ROE was specified in the Settlement Agreement. However, in a subsequent filing WGL reported that an ROE of 10% was used to calculate carrying costs.
12. $98.6 million requested in application, modified to $63 million, to reflect the Hawaii PUC’s decision to separate HECO’s DSM program costs from the rate case to a separate docket.
13. Order granting application for a determination of advanced ratemaking principles for a proposed wind-generation project.
14. Result from two most recent dockets involving wind-power projects.
15. Proceeding to review level of earnings under formula rate plan.
16. Test year utilized is actual year ending September 30, 2007 with pro formas to June 30, 2009 and Rodemacher Unit No. 3 full year operations.
17. The components are as follows: Base Rate Increase $250.1 million; Fuel Cost Savings ($224.4) million; Refund of RPS-3 Carrying Charges ($98) million; Net Decrease ($72.3) millions.
18. Company requested 12.25% ROE.
19. Order granting requests by two electric utilities for permanent rate recovery of costs associated with damages caused by Hurricanes Rita and Katrina.
20. Utilities directed to file full ROE analysis reflecting reduced risk associated with “up-front” recovery of future storm costs.
21. Increase to monthly customer charge for increased operating expense and equipment replacement. Commission also approves “Capital Surcharge” to generate $.546 million over five-year year period to fund capital additions.
22. Figures shown are total revenue requirement, not revenue sufficiency or deficiency. Approved settlement agreement based on $54.4 million total revenue requirement. Company initially requested rates to recover $56.6 million in revenue.
23. Order approving stipulation that decreases electric distribution rates and establishes a new five-year alternative rate plan.
24. Rate plan contains a high-end earnings-sharing provision mandating reliability investments if earnings exceed 11% ROE during term of rate plan.
25. Reflects reduced risk to investors stemming from improvements in capital structure and divestiture of nuclear assets.
26. Settlement agreement.
27. Settlement silent on ROE. Utility continues to use ROE authorized in prior rate case.
28. Demand-side management programs in rate base earn a 5% enhancement on ROE, or 15.6%.
29. The Tracy combined-cycle generating unit earns a 1.5% incentive ROE, or 12.1%.
30. Revenues required under three-year rate plan.
31. Rate order includes earnings-sharing plan allocating 50% of actual earnings above 10.7% ROE to shareholders.
32. Order establishing three-year rate plan.
33. Figure shown is levelized annual increase for each of three rate years ending June 30, 2009, 2010 and 2011.
34. Equity earnings sharing mechanism with 50% sharing of earnings between 10.2% and 11.2%, 7.5% above 11.2%. Figure shown is base figure for revenue requirement.
35. Commission orders further reduction of $53.924 million for issues not settled under stipulation.
36. Last rate order issued 2002.
37. Settlement agreement. ROE not specified.
38. ROE for natural gas distribution utilities set in accordance with OEB Draft Guidelines on a Formula-Based Return on Common Equity for Regulated Utilities (Ontario Energy Board, March 1997).
39. For electricity rate applications (transmission and distribution) the $ shown as requested and approved are the total revenue requirement, not as revenue sufficiency or deficiency.
40. ROE for electricity transmitters and distributors set, beginning on 2007 in accordance with the Report of the Board on Cost of Capital and 2nd Generation Incentive Regulation for Ontario’s Electricity Distributors.
41. Settlement agreement.
42. Settlement agreement. ROE not specified.
43. Application to adjust rates under formula rate plan.
44. Settlement agreement. ROE not specified.
45. Board approves memorandum of understanding (MOU) as a bottom-line settlement in which overall rate level is found just and reasonable.
46. Figure shown stated in MOU pending adoption of alternative regulation plan or order in future rate proceeding.
47. Approved stipulation authorizes stated revenue increase, as well as a four-year, performance-based rate plan.
48. Plan required company to share with ratepayers earnings in excess of 10.5%.
49. Subsequently revised to $34 million.
50. Net of Point Beach nuclear power plant credits. Effective increase for 2009 of $183.5 million net of Point Beach credits.
51. Offset by a credit of $315.9 million for the sale of the Point Beach Nuclear Power Plant. Credit reduced to $240.7 million in 2009.