By: Donald A. Kaplan, William M. Keyser, and Abe F. Johns

On October 16, 2018, the Federal Energy Regulatory Commission (“FERC” or “the Commission”) issued an order (“Order”) that dramatically reforms the way it determines the just and reasonable return on equity (“ROE”) in rate cases. The new methodology abandons FERC’s exclusive reliance on its discounted cash flow (“DCF”) model and will now give equal weight to the DCF, capital-asset pricing model analysis (“CAPM”), and an expected earnings analysis (“Expected Earnings”) to determine if a ROE is unjust and unreasonable. FERC will add a fourth method, a risk premium analysis (“Risk Premium”), to determine the new ROE when it finds a challenged ROE unjust and unreasonable.

While the new method only applies to transmission owners in New England, considering FERC’s enthusiasm for uniformity, the policy will likely be applied to more rate cases in the future and could impact both the electric and gas industries.

I. Background: FERC’s Previous ROE Calculus

The Order on remand, from the DC Circuit Court of Appeals in Emera Maine v. FERC, 854 F.3d 9 (D.C. Cir. 2017), comes as the latest iteration of cases based on several complaints against the collective ROE of the transmission owners in ISO New England, Inc.

The ROE represents the allowed return on utility equity included their cost-of-service rates. Under the famous Hope and Bluefield standards, FERC must set utility rates and returns on investment commensurate with other enterprises of comparable risk and sufficient to attract capital and “assure confidence in the financial integrity of the enterprise . . . .”  FERC ratemaking also “involves a balancing of the investor and the consumer interests.” FPC v. Hope Nat. Gas Co., 320 U.S. 591, 603 (1944).

In these cases, FERC was called upon to address a challenge to the New England transmission owners’ ROE under Section 206 of the Federal Power Act (“FPA”). Under Section 206, FERC first determines if the existing allowed ROE is “unjust and unreasonable.”  If that first finding is made, it then must establish a new just and reasonable ROE to replace the existing rate.

For nearly 40 years, FERC used the DCF method to assess whether a ROE is just and reasonable for a public utility. Under the DCF method, FERC evaluates the expected dividend growth and market-determined yields of a group of comparable utilities with bond ratings the same as or close to the utility or utilities subject to the ROE complaint to generate a range of ROEs with an upper and lower bound, which FERC termed the “zone of reasonableness.”  FERC then identifies a point in that range as the just and reasonable ROE. FERC had been using the midpoint (for multiple utility ROEs) or median (for a single utility) until recently. In early stages of this case, it began looking at various other considerations to adjust the ROE upward. FERC essentially used the new ROE to satisfy both findings it must make under Section 206 of the FPA.

The Court of Appeals ruled that FERC must explicitly find that a ROE is unjust and unreasonable before it can establish a new rate. It was not sufficient for FERC to find that the new ROE it establishes under the DCF method differs from the existing ROE. Rather, the court held that a broad range of ROEs could be just and reasonable under the FPA (although this range was not the same as FERC develops under the DCF method) and that FERC must find that the existing ROE is not in this range before it establishes a new one.

II. FERC’s Decision: A New Calculus

FERC declared an end to its sole use of the DCF model to determine whether a ROE is just and reasonable. Instead, it will use the DCF with two other methodologies (CAPM and Expected Earnings) to determine whether a utility’s ROE falls within the zone of reasonableness. If it finds that it does not, it will then use these three methodologies plus a fourth, Risk Premium, to establish a new rate.

a. Three Additional Methodologies

FERC chose to incorporate the CAPM, Expected Earnings, and Risk Premium methodologies because, among other reasons, “investors use those models . . . to inform their investment decisions.” The basics of each methodology are worth understanding.

The CAPM evaluates risk and cost equity through a formula that adds a “risk-free rate” with a “market-risk premium,” multiplied by a “beta” of the security. The risk-free rate is a proxy number, often based on the yield of 30-year U.S. Treasury bonds. The beta is a measure of the stock’s risk compared to the market. The market risk premium is the difference between the risk-free rate and the expected return on that stock, which is found either by forward-looking estimates, backwards-looking estimates, or a review of investment academics’ and professionals’ estimates.

The Expected Earnings methodology determines the earnings an investor can expect to receive on the book value (the equity of a company’s capital minus the long-term debt) of a particular stock. The analysis either uses backwards-looking estimates, based on historical earnings on book value, or forward-looking estimates based on analysts’ forecasts of the company. The value of expected earnings helps investors gauge the opportunity cost of investing in a specific utility.

The Risk Premium methodology focuses on the investment in stocks, as they hold greater risk than investment in bonds. The methodology examines that “premium” value that a stock investment accrues over a bond investment. The Order noted that “investors’ required risk premiums expand with low interest rates and shrink at higher interest rates.” FERC will compare the interest rates and risk premiums and assess how “investors’ required rate of return have been impacted by the interest rate environment.”

To assess the first prong of the FPA’s Section 206 standard, three of the methodologies (DCF, CAPM, and Expected Earnings) will yield a composite zone of reasonableness from which a spread of presumptively just and reasonable ROEs for utilities with comparable risk profiles will be identified. FERC will establish an overall zone of reasonableness, then subdivide that zone into four “quartiles” centered on the overall midpoint, and upper and lower midpoints of the zone.

b. Comparing ROEs Based on a Utility’s Risk and Presuming ROE Lawfulness

FERC will use the overall midpoint and upper and lower midpoints to anchor three zones of reasonableness, one each for utilities of lower risk, average risk and higher risk utilities. If the subject utility falls with its appropriate zone, FERC will presume that it is just and reasonable. If not, FERC will move on to set a new just and reasonable rate.

For comparison to average risk utilities, the central tendency of DCF, CAPM, and Expected Earnings zones of reasonableness will determine the cost of equity. Those three midpoint/median figures will be averaged along with the Risk Premium number to calculate the ROE of average risk utilities. To assess ROEs for below or above average risk utilities, the midpoint/medians of the lower and upper halves of the zone of reasonableness will be used, respectively.

FERC will continue to determine a utility’s risk profile by two means. First, it compares the utility to a proxy group of companies with similar risk profiles, i.e., utilities within one “notch” of the subject utility’s credit rating. Second, FERC eliminates utilities from the proxy group based on specific circumstances may be unique, such as involvement in a merger or unusually high or low ROEs found under the four methodologies.

Additionally, FERC will use a “composite zone of reasonableness” based on the DCF, CAPM, and Expected Earnings to create a limit to a utility’s total ROE (base ROE plus incentives). Using this composite zone, FERC will dismiss complaints against ROEs that are within that zone, which are seen as presumptively just and reasonable ROEs, unless that presumption is adequately rebutted.

III. Industry Impact: New England and Beyond

The new calculation for ROEs is considered favorable for public utilities. Under the new calculation, there will be less need to account for anomalous market conditions because four distinct methodologies are used. The calculation is expected to identify a more accurate and healthy ROE for utility investors infrastructure investment.

The Order concludes that the new calculus will work to produce more precise ROEs from inception, allowing for less litigation and fewer complaints. During the Commission Meeting on October 18, 2018, Commissioner LaFleur commented positively about the new methodology, noting that it “could help mitigate pancake complaints (i.e., complaints filed while prior cases are still unresolved)” that have created uncertainty in the industry and “add clarity . . . [to] better inform potential litigants” about existing ROEs, as well as “mitigate some of the concerns . . . on the thinness of the survey that underlies the IBES (institutional brokers’ estimate system) growth rates . . . .”

Currently, the new method only applies to the litigation over the ROE for the New England transmission owners. However, given FERC’s desire for uniformity, the future policy could eventually be applied to all rate cases for electric utilities and gas pipelines subject to FERC’s jurisdiction.

By: Elizabeth C. Crouse

State level energy storage incentives have been proliferating in recent months, but it is still not clear exactly when the federal investment tax credit (“ITC”) is available in respect of storage assets. While certain aspects are well known, the industry has been waiting for several years for additional guidance from Treasury on this matter. On September 20, Senators Tim Scott (R-SC) and Michael Bennet (D-Co) sent a letter to Treasury Secretary Mnuchin nudging him to provide that guidance, particularly in regard to whether storage assets installed at operating ITC-eligible facilities qualify for the ITC.

Many readers will recall that earlier this year the Internal Revenue Service released a Private Letter Ruling concluding that the Code Section 25D credit–which bears striking similarities to the ITC–is available in respect of a battery installed after residential solar panels became operational. In our blog post and Energy Storage Handbook section describing that ruling, we noted that similar logic supports an argument that storage assets installed at an operating ITC-eligible facility should also qualify for the ITC. There are also arguments that the ITC should be available in respect of storage assets installed at a facility that produces power that qualifies for the production tax credit, at least if that facility would also qualify for the ITC.

Although storage has caught on or is taking off in many locations, a green light from Treasury regarding ITC qualification could help the industry and lawmakers accomplish many important and increasingly urgent goals, from flattening the duck curve(s) to increasing reliability in rural areas. We look forward to additional action by Treasury on this matter and hope to share it in the new version of our Energy Storage Handbook, which will be released soon.