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:
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:
In Docket No. ER21-864, on January 12, 2021, Meyersdale Storage requested reactive power compensation pursuant to Schedule 2 of the PJM OATT for its 18 MW lithium-ion battery (Facility) which is co-located with GlidePath’s 30 MW Meyersdale Wind Energy Center. The Facility interconnects with Mid-Atlantic Interstate Transmission LLC’s (MAIT) 115 kV Meyersdale North substation in the Pennsylvania Electric Company (Penelec) transmission zone. Meyersdale provides energy and frequency regulation services on a merchant basis to the PJM energy and ancillary services markets and is contractually obligated to provide Reactive Power Service to PJM. It began operation in 2015.
Meyersdale requested reactive power compensation in the amount of $837,000 annually, which it derived using a methodology consistent with AEP. Given that a battery storage facility’s inverter does not function the same as a traditional synchronous generator, Meyersdale did not use the stated “nameplate” power factor as it is not applicable and does not reflect the Facility’s capabilities. Rather, Meyersdale set forth an alternative power factor of 0.70 that differs from the generator nameplate which is traditionally used in an AEP analysis. In response to a protest from the IMM, Meyersdale asserted that, because its data is from testing performed in accordance with PJM Manual 14D requirements, it can operate at significantly lower (i.e. more difficult) power factors than a traditional resource. Meyersdale also asserted that the objective technical descriptions and testing data included with its filing demonstrates Meyersdale’s superior reactive power capabilities, as compared to a conventional resource on a per-MW basis. Meyersdale argued that the IMM’s assertion that “Meyersdale cannot sustain its rated output for a significant period of time” is true for real power for which batteries have output duration limits, but that is irrelevant in the instant filing as it can, in fact, inject or absorb its full reactive power capability at any time, regardless of battery charging conditions (similar to some solar facilities).
In setting the matters for hearing and settlement, FERC stated that under Order No. 841, RTOs and ISOs are required to allow electric storage resources to provide all capacity, energy, and ancillary services that they are technically capable of providing so long as they satisfy the RTOs’/ISOs’ technical requirements. However, FERC was unable to determine, based on the record, whether Meyersdale’s battery storage facility can provide reactive capability consistent with Schedule 2 of the PJM Tariff, and therefore FERC set this threshold question for hearing, along with Rate Schedule in its entirety. The case is in settlement procedures.
In Docket No. ER21-304, in its orders issued in April 2021 and reaffirmed on August 3, 2021, FERC dismissed Cherokee’s submission of a request for reactive power compensation under Schedule 2 of the PJM OATT. FERC found that the Large Generator Interconnection Agreement (LGIA), through which Cherokee claimed entitlement to reactive power compensation, was not in FERC’s authority, since, where a utility is obligated to purchase the total output of a qualifying facility (QF), as in this case, the relevant state exercises authority over the interconnection and the allocation of interconnection costs.
Cherokee owns and operates the Cherokee Energy Center (Facility), which is a (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA). Cherokee sells capacity and energy from the Facility to Duke Energy Carolinas, LLC (DEC) under a Power Purchase Agreement (PPA), which initially was scheduled to expire on December 31, 2020, but has since been extended until the earlier of an ongoing state proceeding concerning the PPA, or August 29, 2021. Cherokee and DEC are parties to a LGIA providing for the interconnection of the Facility to DEC’s system. Cherokee states that the LGIA requires Cherokee to provide reactive service to DEC with compensation to be set forth in the reactive rate at issue in this proceeding. On November 2, 2020, Cherokee filed the proposed reactive rate schedule with FERC. In that filing, Cherokee also invoked the Commission’s reactive service comparability standard, which requires that a transmission provider pay for reactive services within the established power factor range to the extent the transmission provider pays it own or affiliated generators for that service.
FERC found that Cherokee was not selling the real or reactive output from the Facility to a third party nor did Cherokee state its intention to do so, even after the expiration of the PPA. FERC also found that sales of energy and capacity that made pursuant to a state’s regulatory authority under PURPA includes reactive power. It therefore concluded that it did not have regulatory authority of the LGIA.
In Docket No. ER18-1639, FERC applied the revised ROE methodology from Opinion 569 et. seq. and determined the just and reasonable ROE for a single utility, Mystic Generation in New England, by using the average of: (1) the median result of the DCF model; (2) the median result of the CAPM; and (3) the point estimate of the Risk Premium. FERC found that the just and reasonable base ROE for the Mystic Agreement is 9.33%. The Mystic Agreement is a cost-of-service agreement between Mystic and ISO-NE to provide for continued operation of units 8 and 9 through June 2022. FERC found the Mystic facility to be of average risk. The median DCF ROE estimate is 8.12%, the median CAPM ROE estimate is 10.01%, and the Risk Premium point estimate is 9.85%. The average of those values is 9.33%.
In FERC Docket No. ER21-424, on November 16, 2020, Michigan Electric Transmission Company, LLC (METC) filed an application for an order authorizing METC to recover up to $15 million in transmission-related infrastructure costs associated with its electric vehicle (EV) charging infrastructure project (Pilot Project) pursuant to the Commission’s 2009 Smart Grid Policy Statement. METC requested that, if the Commission finds that its application does not satisfy the Smart Grid Policy Statement criteria, the Commission alternatively consider its application under FPA section 205 independent of the Smart Grid Policy Statement. METC also requested that the Commission authorize METC to recover 100% of abandoned plant costs if the Pilot Project is abandoned for reasons beyond METC’s control. In April 2021, FERC denied METC’s request as FERC found the request premature because it is unclear whether some or all components of the Pilot Project are subject to the Commission’s transmission-related ratemaking authority under the FPA (will the assets be FERC jurisdictional). FERC provided guidance to METC in its order. It stated that METC could, in a subsequent filing: (1) specify the location of the DCFC stations; (2) confirm whether the AC-to-DC converter will be included in the Pilot Project; (3) demonstrate that METC can legally own the proposed facilities; and (4) demonstrate that its facilities qualify as transmission (by providing either (a) sufficient information for the Commission to evaluate the proposed assets according to the Seven Factor Test, including information such as the configuration and voltage level of the proposed assets, or (b) a recommendation from the Michigan Commission on the classification of the proposed assets that evaluates them according to the Seven Factor Test).
In Opinion No. 575 issued by FERC on May 20, 2021, in ER13-1508 through 1513, FERC set an ROE of 10.37% for the sales of capacity and energy among the Entergy Operating Companies. FERC determined the ROE based upon the revised base ROE methodology that it adopted in Opinion 569, 569A and 569 B (the MISO ROE case). Entergy submitted the Unit Power Sales Tariff (Tariff), which contained an ROE component, on May 17, 2013. The Tariff established a general rate schedule for making unit power purchases or power sales between any of the Entergy Operating Companies. Entergy explained that the Tariff would ensure that the six then-existing Service Schedule MSS-4 transactions in which Entergy Arkansas is obligated to sell capacity and energy to the other Entergy Operating Companies continue after Entergy Arkansas withdrew from the Entergy System Agreement and, along with the other Entergy Operating Companies, joined MISO. The Tariff would also govern any new agreements for capacity and energy sales between Entergy Arkansas and the other Entergy Operating Companies, and sales between other Entergy Operating Companies if and when they withdraw from the System Agreement.
FERC ordered a 10.37% base ROE in the Tariff effective December 19, 2013and directed Entergy to submit a refund report and refunds.
Background: Historically, the Entergy Operating Companies’ generation and transmission facilities operated as a single system under the Entergy System Agreement. Service Schedule MSS-4 of the System Agreement governed the purchases and sales of energy and capacity among the Operating Companies. On April 25, 2011, the Entergy Operating Companies announced a proposal to join MISO, with a target implementation date of December 19, 2013, to coincide with Entergy Arkansas’ withdrawal from the System Agreement. Prior to its withdrawal from the System Agreement in 2013, Entergy Arkansas made sales to Entergy Louisiana and Entergy New Orleans under Service Schedule MSS-4. Entergy committed to make an FPA section 205 filing by mid-2013 to establish an “MSS-4-like” rate schedule to govern ongoing sales of energy and capacity between Entergy Arkansas and the other Entergy Operating Companies at cost-based rates outside of the System Agreement. This case involved the MSS-4-like rate schedule.
On March 31, 2021, FERC issued Opinion 574 which concerns the reactive power revenue requirement of Panda Stonewall, a generator in PJM. This case has been pending at FERC for some time - the ALJ previously issued her initial decision on April 26, 2019. Also on March 31, FERC denied a petition for declaratory order requested by several generator owners as FERC determined the reactive power revenue requirement issues included in their request are best resolved on a case-by-case basis and the decision in Panda Stonewall provides guidance on the issues. Here are the major findings in Opinion 574 involving Panda:
 ATSI, 119 FERC ¶ 61,020 at P 27.
 See, e.g., Bluegrass Generation Co., L.L.C., 118 FERC ¶ 61,214, at P 21 (2007) (Bluegrass) (MISO); Calpine Oneta Power, L.P., 116 FERC ¶ 61,282, at P 50 (2006) (Southwest Power Pool, Inc.); Rolling Hills Generating, L.L.C., 109 FERC ¶ 61,069, at P 12 (2004) (PJM).
 See id. (“We agree with AEP (and the judge) that the allocation factor should be based on the capability of the generators to produce VArs . . .”); Va. Elec. & Power Co., 114 FERC ¶ 61,318 at P 3 (citing AEP, 88 FERC at 61,457) (explaining that the AEP methodology is used “to compute the portion of plant investment attributable to reactive power production” (emphasis added)).
 See S. Co. Servs., Inc., 80 FERC at 62,080-81.
 See AEP, 88 FERC at 61,457; Va. Elec. & Power Co., 114 FERC ¶ 61,318 at P 3.
 VRR Curve Order, 149 FERC ¶ 61,183 at P 76 (emphasis added). We note that NYISO, 158 FERC ¶ 61,028, a case upon which Panda relies, was similarly about establishing a market benchmark and does not support any cost of capital generally applicable in a cost-of-service proceeding.
 See 2014 CONE Study at iii.
 Id. at 36.
 Chehalis, 123 FERC ¶ 61,038 at P 167; see also Dynegy, 121 FERC ¶ 61,025 at PP 54-55.
 See, e.g., Bluegrass, 118 FERC ¶ 61,214 at P 86; Calpine Fox LLC, 113 FERC ¶ 61,047, at P 17 (2005).
On October 20, 2020, in Docket EC21-10, NextEra Energy Transmission, LLC (NEET), GridLiance West LLC, GridLiance High Plains LLC, and GridLiance Heartland LLC (collectively, GridLiance) filed an application requesting authorization for a transaction whereby NEET will acquire the upstream ownership interests in GridLiance. FERC reviewed the proposed transaction and, on March 18, 2021, conditionally authorized it as consistent with the public interest. The condition FERC placed on its approval is because the Applicants representations were insufficient to show that the Proposed Transaction will not result in the cross-subsidization of a non-utility associate company by a utility company, or in a pledge or encumbrance of utility assets for the benefits of an associate company. Therefore FERC required that the Applicants must show that they meet the criteria for application of the safe harbor (which they claimed in their filing) by filing a new Exhibit M (verification regarding cross-subsidization of non-utility associate company or pledge of encumbrance) no later than 60 days from the issuance of this order.
The GridLiance Transco’s partner with municipal electric utilities, electric cooperatives, and joint action agencies to solve transmission issues, optimize its partners’ systems, and help manage costs of these systems to the benefit of its partners and the broader transmission grid. Blackstone Power & Natural Resources Holdco, L.P. (Blackstone) has partnership interests in the Gridliance Transcos. Following the Proposed Transaction, Blackstone will no longer own any direct or indirect interests in GridLiance Transcos, and NEET will become the indirect owner of GridLiance Transcos.
In its Order, FERC found that:
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