On May 21, 2020, the Federal Energy Regulatory Commission (“FERC” or “Commission”) approved two orders by 3-1 votes revising its methods to estimate electric, natural gas and oil utilities’ returns on equity (“ROE”).[1]  Return on equity is one of the most contentious issues in cost-of-service proceedings before FERC, and FERC’s guidance is unlikely to alter that.  In many important ways, the guidance significantly deviated for electric utilities and pipelines, which raises a number of issues regarding whether such deviations are supported by each industry’s risks.

Revised Guidance for Calculating ROEs

FERC guidance was provided in two separate orders.  First, FERC issued ABATE, which addressed electric utility ROEs in an ongoing Section 206 Federal Power Act (“FPA”) complaint.  Second, FERC issued the May 21 Policy Statement, which addressed ROEs more generally for pipelines.


ABATE granted rehearing of FERC Opinion No. 569, which altered FERC’s traditional ROE methodology and provided a framework for analyzing FPA Section 206 complaints associated with electric utility equity returns.[2]

ABATE modified Opinion No. 569 by:

  • permitting electric utilities to utilize the risk premium model, in addition to the Discounted Cash Flow (“DCF”) and capital asset pricing model (“CAPM”) methodologies;
  • weighting short-term growth rates at 80%, and long-term growth rates at 20%, of total growth to be used in a two-step DCF methodology;
  • allowing Value Line growth rates in future CAPM analyses;
  • increasing the high-end outlier test from 150% to 200% of the median result of all of the potential members of a utility proxy group; and
  • dividing the range of the composite zone of reasonableness into equal thirds, not the quartile approach adopted in Opinion No. 569.

The May 21 Policy Statement

The May 21 Policy Statement discusses the Commission’s policies for forming proxy groups in pipeline proceedings, and additional changes to its ROE policies for pipelines.  The May 21 Policy Statement modifies the two-stage DCF calculations for natural gas and oil pipelines used by the Commission for the past two decades, and proposes to equally weight those results with the results of CAPM determinations that incorporate a single-stage DCF computation using Value Line estimates for the source of growth data.[3]  The new May 21 Policy Statement suggests that FERC will entertain proposals embodying a wider range of computational and conceptual improvements for pipeline ROE determinations.  For instance, the Commission indicates in the May 21 Policy Statement that it might consider case-by-case justifications for (1) instituting a “natural break” analysis for reviewing the results of pipelines (PP 87-90), (2) implementing the Expected Earnings method for establishing ROE (P 75), (3) modifying the 50% reduction in the long-term growth rate previously applied to master limited partnerships (P 29 n.70), (4) applying enhanced “flexibility” in determining how to populate proxy groups, for instance by relaxing the prior criterion that looked to whether at least half of a potential proxy group member’s assets or operating income could be attributed to interstate pipeline operations (P 65), or whether an entity with predominantly Canadian pipeline operations could be included in the proxy group.  However, this additional flexibility did not extend to modifying the existing weighting of expected growth rates for pipelines by giving two-thirds weight to a short-term growth projection derived from the Institutional Brokers Estimated System and one-third weight to a long-term growth projection.[4]  The May 21 Policy Statement asserts generally that FERC will not use the risk premium model.  It also encourages oil pipelines to file revised Form No. 6, page 700s reflecting the revised ROE policy.[5]

The May 21 Policy Statement also reiterated that absent unusual circumstances showing that the pipeline faces anomalously high or low risks, FERC will continue to set the pipeline’s cost-of service nominal ROE at the median of the zone of reasonableness.[6]

FERC policy statements are non-binding pronouncements of policy, rather than binding de facto rules.  When the non-binding nature of the Policy Statement is combined with the high degree of flexibility it suggests is available in methods that can be used to set pipelines’ ROE, the result is quite a bit of discretion both for pipelines in filing, and a current or future Commission   in setting, ROEs,  including by a new majority of FERC commissioners at some subsequent date.


FERC’s change in policy provides litigants in cost-of-service rate proceedings greater flexibility to attempt to match a utility’s actual risk with its equity return.  Unlike many inputs in cost-of-service ratemaking, a utility’s equity return is not directly observable.  Instead, FERC has estimated such returns based on equity market data, analyst estimates and government data.  FERC’s new policy expands the information that FERC will consider when setting returns.  However, the May 21 orders’ different treatment of the electric utility and natural gas pipeline industries’ ROE calculations implicitly or explicitly raise a number of issues, which along with the enhanced flexibility noted above for pipeline ROE determinations, likely will create additional controversy in the rate-setting process.

One series of questions involves the different methods that would be applied as between regulated electric utilities and pipelines.  For instance, short-term growth rates are more heavily weighted for electric companies than for pipelines, suggesting that long-term risks are not as significant to investors in electric utilities as are those of pipelines.  It may be argued, however, that the short-term growth factor is equally, if not more, important to investors in pipelines.  Electric utilities’ wires likely will continue to be needed for decades to come, even if renewables and distributed resources’ penetration of the market increases; in contrast, many jurisdictions have announced plans to transition to carbon free or significantly reduced carbon outcomes within the period of time commonly used by FERC to depreciate transmission pipelines.  Some jurisdictions already have implemented bans on new connections for natural gas service. While conjecturing that the shale production revolution caused the pipeline industries to “become . . . less mature” (May 21 Policy Statement, 171 FERC ¶ 61,155 at P 33), the May 21 Policy Statement fails to acknowledge, much less account for, the extraordinarily steep production decline curves of shale wells, which produces a much narrower “tail” of production in years subsequent to the initial first year surge, meaning that if shale drillers ramp down activities for even a brief period, they will fail to replace prior levels of production, leaving pipelines’ capacity underutilized. Given these circumstances, giving greater weight in pipelines’ ROE calculations to long term growth rates than in calculating ROEs for electric utilities may be illogical.

Another disparity between calculation of the ROE for electric utilities and for pipelines involves the application of the risk premium method to the former but permitting its use by pipelines only on a case-by-case basis where its proponents can demonstrate adequate data exist. In fact, the perceived absence of adequate data is a deficiency that may be illusory.  This may be fertile ground for litigants.  Some participants may criticize as well the Commission’s justification for concluding that the risk premium method is automatically valid for electric utilities but not pipelines, especially when in earlier pronouncements, the Commission found that the risk premium method is a helpful indicator of how investors’ required rates of return have been impacted by the interest rate environment,[7] and the May 21 Policy Statement asserts that there “is no basis for distinguishing between investors in natural gas and oil pipelines in this context” (involving CAPM), because “investors employ various methods for determining cost of equity” (id. at P 27).

The May 21 Policy Statement presents a number of conundrums even standing alone.  It appears to mark a new level of receptivity to considering the equity returns of Canadian pipeline operations when selecting a proxy group, although for years FERC contended that the Canadian pipelines should not be included in proxy groups.[8]   There are a number of significant differences between pipeline regulation in Canada and the U.S.  For instance, Canadian oil pipelines must be authorized for construction, or abandonment, by the federal regulator; interstate oil pipelines face no comparable FERC requirement in the U.S.  For years, as facilitated by NAFTA, oil and natural gas exploration, development and marketing in Canada and the U.S. grew increasingly  interdependent; with the rise of shale production in the U.S., however, the dependence of northern states upon Canadian production has been severely diminished by Marcellus, Utica and Bakken volumes.  In the last half dozen years, Canada’s National Energy Board (i.e., Canada’s energy regulatory agency) allowed Canada’s largest interprovincial methane pipeline to set floor, not ceiling, rates for interruptible and short-term firm transportation rates,[9] a rate regime that FERC does not seem close to embracing.  If  proxy groups include entities that have lower risk than U.S. regulated pipelines, the resulting estimated ROE should be adjusted accordingly. Moreover, the May 21 Policy Statement fails to consider whether intrastate U.S. pipeline operations would be better proxies.

Additionally, FERC’s May 21, 2020 ROE decisions leave several unanswered questions:

  1. Does the May 21 Policy Statement provide adequate flexibility to reflect  risks from financial distress in the exploration and production community?
  2. Is the diminution in the value, and increased risk, of natural gas storage service occasioned by the extraordinary growth in wellhead production also adequately reflected in the ROE results produced by the approved methodologies?
  3. Do the approved methods reflect the risks of diminished hydrocarbon production and reduced demand for transmission services resulting from depressed commodity values?
  4. Do the approved methods adequately reflect the increasing level of risk to hydrocarbon pipelines of various states’ de-carbonization plans?
  5. Has systematic risk (often denoted by the “b” variable in the CAPM formula) been fundamentally disrupted in the last 60 days by the COVID-19 crisis, the related financial panic, and the Federal Reserve’s responses thereto?
  6. Are market indices, from which some of the data are collected to create macro measures of risk, being distorted by the performance of a handful of technology companies whose fortunes bear little relationship to those of oil and gas pipelines, and the products of which if used to enhance efficiency, will diminish the consumption of electricity?
  7. Will the risk premium methodology, should it rely upon historical data, mis-state the premium on a prospective basis in light of the Federal Reserve’s recent decision to purchase a wide array of debt (and potentially other types of securities)?
  8. If another methodology depends upon using DCF in its computation, how does FERC avoid the criticism that it is in essence overly reliant on the DCF methodology?
  9. Similarly, if the risk premium method is simply a re-casting of the CAPM, does use of both of those models to calculate ROEs for electric utilities in essence double-count that input and dilute DCF?

[1]              Association of Businesses Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, Inc., 171 FERC ¶ 61,154 (2020) (“ABATE”); Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines, 171 FERC ¶ 61,155 (2020) (“May 21 Policy Statement”).

[2]              Association of Businesses Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, Inc., Opinion No. 569, 169 FERC ¶ 61,129, at P 1 (2019) (“Opinion No. 569”).

[3]              Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity, 123 FERC ¶ 61,048, at P 3 (2008) (“2008 Policy Statement”)

[4]              2008 Policy Statement, 123 FERC ¶ 61,048 at P 6.

[5]              2008 Policy Statement, 123 FERC ¶ 61,048 at P 6.

[6]              El Paso Nat. Gas Co., Opinion No. 528, 145 FERC ¶ 61,040, at P 592 (2013).

[7]              See Ass’n of Businesses Advocating Tariff Equity v. Midcontinent Indep. Sys. Operator, Inc., 165 FERC ¶ 61,118, at App. (2018)

[8]              E.g., Portland Nat. Gas Transmission Sys., Opinion No. 510, 134 FERC ¶ 61,129, at P 224 (2011); May 21 Policy Statement, 171 FERC ¶ 61,155 at P 57 n.126.

[9]              See National Energy Board, Re TransCanada Pipelines Limited RH-003-2011 (March2013) (Reasons for Decision).