​FERC issued Opinion 870 on November 18, 2021 in Docket Nos. ER17-998, EL17-61 and EL18-91 involving the DATC Path 15 transmission project in California.  The central issue before FERC in these dockets is whether the transmission revenue requirement (TRR – stated rate, not a formula rate) reduction proposed by DATC Path 15, LLC (DATC) in its February 17, 2017 filing (2017 Filing), revising Appendix I to its Transmission Owner Tariff (Path 15 Tariff), is just and reasonable and not unduly discriminatory or preferential. FERC reversed the Presiding Judge’s determination in the Initial Decision on the just and reasonable return on common equity (ROE) for use in DATC’s TRR, including the composition of the starting proxy group and the use of Expected Earnings in the ROE methodology, and it found that the appropriate ROE for DATC is 10.86% (the Initial Decision found that the current ROE to be just and reasonable). FERC affirmed the Presiding Judge’s findings of fact and conclusions of law regarding test period adjustments and the appropriate effective date for the corporate income tax adjustment required by the Tax Cuts and Jobs Act.  FERC ordered DATC to file a refund report detailing what portion of the refund is attributable to the ROE reduction and what portion is attributable to the reductions from the Tac Cut and Jobs Act. 
 
The Path 15 Upgrade is an 84-mile, 500 kilovolt (kV) transmission line built along the existing Path 15 corridor in California to relieve a constrained congestion point. In 2001, FERC specifically recognized the Path 15 corridor as a significant problem area requiring incentives for investment to alleviate costly congestion.  The upgraded Path 15 transmission line went into operation in December 2004, adding roughly 1,500 megawatts (MW) to the existing 5,400 MW of transmission capacity from southern to northern California, and increasing transmission capacity from north to south by about 1,100 MW.   On June 12, 2002, the Commission accepted a letter agreement among the Path 15 participants that constituted the first step in a process that led to the addition of transmission capacity along California’s Path 15.  The letter agreement set forth rate principles to provide some certainty to the financial community and to enable the Path 15 Participants to obtain necessary financing.  The letter agreement provided for, among other things, the use of a 13.5% ROE in the calculation of a to-be-filed TRR so as to promote the timely construction of the transmission facilities. 
 
In February 2017, DATC filed its fourth triennial rate case proposing to revise Appendix I to its Path 15 Tariff to reduce its TRR from $25.9 M to $25.6 M. DATC also stated that for the first time in its rate filings, the upper end of the zone of reasonableness had fallen below 13.5%.  DATC calculated the zone of reasonableness using the Commission’s standard two-step discounted cash flow (DCF) methodology at a range of 6.10% to 11.19%.  However, DATC stated it was entitled to an upward adjustment to this zone, resulting in a proposed range of 7.44% to 12.53%.  DATC stated this adjustment was consistent with Commission precedent and necessary to account for anomalous capital market conditions surrounding the Path 15 Upgrade.  DATC stated that if the Commission accepted the 2017 Filing without setting the matter for hearing, its ROE would be capped and set at 12.53%. If the Commission instead set the matter for hearing, DATC stated that it would update its cost-of-service numbers prior to hearing and seek a 13.5% ROE, bounded by the upper end of the zone of reasonableness. 
 
In April 2017, pursuant to delegated authority, the Director of Electric Power Regulation – OEMR West – accepted the DATC filing, subject to refund, and set it for settlement and hearing procedures.  In October 2017, FERC denied the request for an upward adjustment to the ROE.  FERC recognized the significant rate and service reliability benefits, including a substantial decrease in actual and potential congestion, along with a substantial increase in system reliability. Consistent with the approach taken in the 2011 and 2014 Rate Cases and in recognition of the unique nature of the Path 15 Upgrade, FERC directed the Presiding Administrative Law Judge (Presiding Judge) to determine the appropriate range of reasonable returns, and to set the ROE at the upper end of the range, not to exceed the filed 13.5%.  FERC held the hearing in abeyance to provide parties with an opportunity to settle, but settlement discussions were later terminated, and an evidentiary hearing ensued.
 
In arriving at its DATC decision, FERC applied the revised ROE methodology from Opinion 569, as modified in 569-A and 569-B, and found that certain modifications were required to apply the Opinion No. 569 methodology to the facts and circumstances of DATC because (1) DATC’s ROE is an all-in incentive ROE and not a base ROE; and (2) the Commission had already determined that DATC’s ROE should be set at the upper end of the range of reasonable returns, not to exceed the filed 13.5%. Applying this modified ROE methodology, FERC found that the composite zone of reasonableness was from 7.55% to 10.86%, and that DATC’s existing 13.5% ROE was entirely outside of this range, making the existing rate unlawful under the first prong of FPA section 206.  Since FERC had previously determined that the DATC ROE would be set at the high end of the zone of reasonableness, FERC determined under the second prong that the just and reasonable ROE should be 10.86%, as that is the highest combination of base ROE and ROE adders that FERC would grant using its new ROE methodology.
 
FERC found that it was appropriate to apply the DCF analysis from the revised ROE methodology established in Opinion No. 569. Specifically, FERC held that: (1) only the IBES short-term growth projection should be used for calculating the (1+.5g) adjustment to the dividend yield instead of a composite growth rate; (2) a revised low-end outlier test applied under which FERC excluded from the proxy group companies with ROEs that do not exceed the Baa bond yield by at least 20% of the Risk Premium from the CAPM analysis; (3) a revised high-end outlier test applied, under which FERC treated any proxy company as high-end outlier if its cost of equity estimated under the model in question is more than 200% of the median result of all of the potential proxy group members in that model before any high or low-end outlier test is applied, subject to a “natural break” analysis; and (4) the long-term growth rate should be given 20% weighting and the short-term growth rate 80% weighting in the two-step DCF model.  FERC also found that it was appropriate to apply the CAPM analysis (not the empirical CAPM) from the revised ROE methodology established in Opinion No. 569.  FERC found that it was appropriate to apply the Risk Premium analysis from the revised ROE methodology established in Opinion No. 569.  FERC disagreed with the Initial Decision directly including the Expected Earnings in determining the just and reasonable ROE it found here as it did in Opinion 569, 569-A, and 569-B that the Expected Earnings model is not market-based and did not satisfy the requirements in the Supreme Court Case Hope.  As to adjustments made to the proxy group, FERC excluded Avangrid from the proxy group since it is a controlled company (DATC had included Avangrid).
 
FERC determined that substantial evidence supports a finding that the appropriate effective date of the adjustment to account for the Tax Cuts and Jobs Act was January 1, 2018.   DATC has one locked-in rate period from April 21, 2017 through January 1, 2018, the effective date of the Tax Cuts and Jobs Act, and a second rate period from January 1, 2018 thereafter. 

​On November 18, 2021, in Docket No. ER18-1639, FERC issued an order on rehearing, lowering the ROE for Mystic from that determined its order (9.33%) to 9.19%.  Mystic Generating Station in New England is operating under a cost-of-service contract as ISO-NE has determined that the facility is needed for reliability while the owner of the facility requested permission to cease operations.  FERC made this change for the following reasons:
 

1. Natural break analysis in DCF – FERC agreed that Otter Tail, which was 147 basis points higher than the next DCF result, should be removed from the DCF results.  FERC explained that the natural break analysis gives them the flexibility to determine whether a given proxy company is an outlier, or whether it presents useful information considering the particular array of ROEs being presented.  FERC also reiterated that its application of the natural break analysis will be dependent on the facts specific to each case.  The exclusion of Otter Tail results in a median DCF result of 7.70% and the average of the medians of the DCF, CAPM and Risk Premium of 9.19%.
2. FERC had excluded Avangrid from the proxy group as it is a controlled company (more than 50% of stock owned by one entity – Iberdrola).   FERC excludes controlled companies as the distortionary effect on stock prices for controlled companies exists for as long as the controlled status endures.  FERC concluded that Avangrid features a dramatically different ownership structure than any other proxy group company as well as Mystic, rendering it in appropriate proxy group member.   
3. FERC reaffirmed that Dominion should be excluded from the proxy group due to M&A price distortion (Dominion acquired SCANA Corp).    

​On November 18, 2021, FERC issued a notice of inquiry in Docket RM22-2 regarding reactive power compensation.  Comments are due mid-January 2022 and reply comments are due mid-February 2022. 
 
FERC set its approach to cost-of-service reactive power compensation back in 2002 when it determined that all resources that have actual cost data and support documentation should use the reactive power compensation approach from Opinion 440 involving American Electric Power Company.  Since that time, many generators no longer use the FERC Uniform System of Accounts nor provide FERC Form 1, as they are exempted under their market-based rate authority.  In addition, Opinion 440 was based upon synchronous generating resources (coal, natural gas, hydro), while many filings to FERC in recent times involve wind and solar facilities (nonsynchronous resources).  These and other reasons prompted FERC to issue this NOI to consider changes to how generating resources receive compensation for reactive power.  Here are the areas FERC is exploring and for which FERC seeks answers to questions:
 

1. Power factor degradation – how does a resource’s reactive power capability degrade over time, should FERC consider degradation when setting reactive power compensation, for how long during a test should a resource be required to maintain its maximum real power output while operating across its claimed reactive power range, how frequently should testing be performed.
2. Nonsynchronous resources – is the Opinion 400 methodology appropriate for these resources, should the amount of compensation consider the intermittent availability of these resources, how to treat solar resources which can have a much lower power factor than synchronous resources.
3. Support documentation – should FERC require those resources that do not use the Uniform System of Accounts or file FERC Form 1 to complete a standardized form with recognized schedules that provide the needed reactive power investment and cost information.
4. Market-based reactive power compensation – in RTOs with capacity markets, how do resources account for reactive power compensation when determining their capacity offers, can there be double recovery of reactive power compensation.
5. Opinion 440 methodology – does this methodology accurately reflect a resources investment and costs in real and reactive power, what is the appropriate time for reactive compensation under Opinion 440 to remain in effect
6. Alternative reactive power compensation methodologies – what other methodologies exist for compensating resources for providing reactive power - some ISOs use flat rate approaches (what are benefits and drawbacks), what are the pros and cons of using an approach whereby the lowest cost resource that provides reactive power sets the rate that every resource is paid.
7. Resources connected to distribution system – are they capable of providing reactive power to the transmission system, should compensation depend on whether the ISO/RTO has control of such resources.