​On October 26, 2020, Baltimore Gas and Electric (BGE), a subsidiary of Exelon, filed in Docket No. ER21-214 revisions to its transmission formula rate to align calendar year revenue and revenue requirement in its Projected Annual Transmission Revenue Requirement and in its Annual True-up Adjustment.  To accomplish this alignment, BGE seeks to adjust the true-up mechanism in its Formula Rate to: (1) use actual revenues, rather than projected revenues, for a 12-month period as the basis for the true-up; and (2) true-up those actual revenues for a given January to December time period to actual costs for that same January to December time period, instead of truing up revenue projections for a June to May time period to actual costs for the January to December time period, as is done in BGE’s current transmission formula rate. This timing adjustment revision is consistent with FERC precedent and have been implemented for several utilities, including Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company (all Exelon subsidiaries). 
 
The filing also revises the method for developing the forecasted revenues for the upcoming year, which are used to establish BGE’s projected revenue requirement – the basis for its transmission rates. Under the new methodology, BGE will use projected values for plant, accumulated depreciation, depreciation and amortization expense, other income tax adjustment expense, and accumulated deferred income taxes (“ADIT”) for the upcoming year when developing its projected transmission revenue requirements. All rate base items in the projected and true-up revenue requirements will also be calculated using the average of 13 monthly balances with the exception of ADIT, which will use a simple average.6 Non-plant related rate base items and capital structure will continue to use historical data; however, this data will be 13-month average balances as opposed to year-end balances as done with the current Formula Rate.  To adhere to tax normalization rules, ADIT would reflect the application of proration rules.  Historical data will still be used for non-plant related rate base components of the projected revenue requirement (e.g., prepayments, reserves, materials and supplies), other expenses (e.g., Operating & Maintenance expenses and Taxes Other Than Income Taxes) and capital structure, as these items tend to have less year-to-year variability compared to plant-related items. 

​On November 16, 2020, in ER21-424, Michigan Electric Company (MET) applied to FERC for authorization to recover in electric transmission rates: (1) up to $15 million in costs associated with the construction of new transmission facilities and the deployment of advanced technology to support the development of new electric vehicle (EV) infrastructure in the State of Michigan (EV Infrastructure Pilot Project or Pilot Project); and (2) recovery of 100 percent of abandoned plant costs in the event the EV Infrastructure Pilot Project is abandoned for reasons beyond MET’s control. MET’s EV Infrastructure Pilot Project will facilitate the development and deployment of publicly accessible Direct Current Fast-Charging (DCFC) EV stations to serve long-haul medium- and heavy-duty commercial vehicles, trucks, and buses, and will provide data and information needed to assess how electrification trends and the deployment of EV infrastructure may impact the operation and reliability of the interstate transmission grid regulated by FERC.  METC can already recover the costs of the Pilot Project through its existing formula rate. However, the 2009 Smart Grid Policy Statement allows applicants like METC to submit a section 205 filing to provide “the assurance of cost recovery” and to mitigate against the risk of “future review and challenge.” 

On November 19, 2020, in EL14-12, FERC issued an Order on Rehearing regarding the MISO TO’s ROE.  FERC determined:
 

1. FERC will continue applying the ranges of presumptively just and reasonable base ROEs established in Opinion No. 569-A by dividing the overall composite zone of reasonableness into three equal portions.  FERC was not persuaded by the requests for rehearing contending that the Commission’s ranges of presumptively just and reasonable base ROEs must be divided into quartiles, especially because doing so excludes the bottom eighth and top eighth of the overall zone of reasonableness and would thereby exclude “potentially lawful ROEs.”  Additionally, FERC continues to find that using a range of presumptively just and reasonable ROEs to establish base ROEs for MISO TOs is appropriate considering Emera Maine.  Given the court’s explanation that there is “‘a substantial spread’ of potentially reasonable rates,” FERC believes that a range of potentially just and reasonable ROEs will likely be the best evidence of what is a just and reasonable ROE for the utility at issue.
2. FERC found that the range of presumptively just and reasonable ROEs, considered alongside other evidence in the record, provides an initial indication of whether an existing ROE may be unjust and unreasonable.  Critically, this presumption is rebuttable.  Accordingly, the Commission can still find that the ROE is unjust and unreasonable based upon the preponderance of the evidence, even if it falls within the applicable range of presumptively just and reasonable ROEs.
3. The MISO TOs should be treated as average risk.
4. Continue to give the long-term growth rate a 20% weighting and the short-term growth rate an 80% weighting in the DCF growth rate.
5. FERC disagreed that allowing the use of Value Line growth rates in the CAPM makes for reasoned decision-making.  As the Commission explained in Opinion No. 569-A, “diversifying data sources may better reflect the data sources that investors consider in making investment decisions.”  Further, the Commission noted that Value Line projections incorporate the input of multiple analysts and are updated regularly.  FERC found that Value Line data, by virtue of regular updating, a robust review process, and wide use among investors, is sufficiently robust to warrant inclusion in the CAPM ROE determination.  FERC reiterated that the Commission stated that it “will evaluate proposals to use Value Line short term growth rates in the CAPM based on the evidence produced.”
6. FERC continued to find that the CAPM should use a one-step DCF for its risk premium calculation.  As the Commission noted in Opinion No. 569-A, this is because the rationale for using a two-step DCF methodology for a specific group of utilities does not apply when conducting a DCF study of the dividend-paying companies in the S&P 500.  As the Commission has found already, a long-term component is unnecessary because of the regular updates to the S&P 500.
7. FERC also continued to find reasonable the use of Value Line adjusted betas in the CAPM methodology, as well as the use of raw betas based on the NYSE in the size premium adjustment.  FERC continued to find that the size adjustment is necessary to correct for the CAPM’s inability to fully account for the impact of firm size when determining the cost of equity. 
8. FERC continued to find that the Risk Premium model is sufficiently distinct from the CAPM to use in the ROE analysis.  For example, the Risk Premium model adds data diversity by using corporate utility bond yields while the CAPM uses Treasury bond yields.
9. FERC clarified that the Risk Premium model adopted in Opinion No. 569-A employs historical Baa utility bond yields, although the Commission inadvertently used projected bond yields in the Risk Premium analysis referenced in the Briefing Order.  FERC clarified that, consistent with the Commission’s finding in Opinion No. 551, Risk Premium models should employ historical and not forward-looking bond yields.
10. FERC sustained the result that the Commission reached on the high-end outlier test in Opinion No. 569-A and will continue to treat any proxy company as a high-end outlier if its cost of equity estimated is more than 200% of the median.  The high-end outlier test is an objective test to identify proxy group ROEs that are irrationally or anomalously high because, for example, they are the result of atypical circumstances that are unrepresentative of the subject utility’s risk profile or are otherwise likely to be in error.  FERC noted that the high-end outlier test is the first, but not the only, method for screening a high-end result from the proxy group.   
11. In summary, FERC made minor modifications to address errors in the Risk Premium application.  However, those modifications do not affect the 10.02% base ROE that was adopted in Opinion No. 569-A.  Accordingly, FERC continues to require the MISO TOs to adopt a 10.02% base ROE effective September 28, 2016, the date Opinion No. 551 initially required the MISO TOs to adopt a 10.32% base ROE.  FERC required that the MISO TOs provide refunds based on that 10.02% base ROE, with interest, for the First Complaint proceeding’s 15-month refund period from November 12, 2013 through February 11, 2015, and for the period from September 28, 2016 to the date of this order.  Further, FERC sustained the Commission’s dismissal of the Second Complaint in Opinion No. 569-A and its finding that no refunds will be ordered in the Second Complaint proceeding.