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:
On February 2, 2021, in Docket No. 20-2277, Jersey Central Power and Light (“JCP&L”) filed a settlement agreement establishing a transmission formula rate that it filed in October 2019. At that time, JCP&L had in effect a stated transmission rate. The new transmission formula rate is effective January 1, 2020. The amount of difference between the settled transmission rates versus that allowed by the Commission to go into effect based upon the JCP&L filing will be included in the annual true-up adjustments for 2020 and 2021 and not refunded directly to customers. The settlement provides for the following:
In Docket AC20-103, earlier in 2020, the law firm of Locke and Lord filed with FERC a request for FERC to provide guidance on the proper accounting for wind, solar facilities, and other non-hydro renewable resources. FERC denied this request but acknowledged that the industry would benefit from its guidance on the accounting treatment of solar and wind generating assets. To that end, on January 19, 2021, FERC initiated a Notice of Inquiry (NOI) in Docket RM20-19 in which FERC is soliciting input from interested parties to evaluate the need for accounting guidance and to consider creating separate categories of accounts for wind and solar generating assets. First, FERC seeks comments on whether to create new accounts within the Uniform System of Accounts (USofA) for non-hydro renewable energy generating assets, and, if so, how such accounts should be organized. Second, FERC seeks comments on how to modify FERC Form No. 1 to reflect any new accounts. Third, FERC seeks comments on whether to codify the proper accounting treatment of the purchase, generation, and use of renewable energy credits (RECs). Finally, FERC seeks comments on the rate setting implications of these potential accounting and reporting changes. Comments are due in mid-March and responsive comments due mid-April.
 Non-hydro renewable assets, as referred to in this notice, are production assets other than hydroelectric generators such as solar, wind energy, geothermal, biomass, etc., that rely on the heat or motion of the earth or sun’s radiation to produce energy. Specifically, these are denoted as renewable because the power production is based on a fuel source that is not consumed or destroyed by the generation process, such as buried hydrocarbons (coal, oil, natural gas), or the decay of rare irradiated heavy metals (nuclear). Biomass (trees, nut shells, grain husks and stalks, etc.) is considered renewable, despite its hydrocarbon source being consumed, due to its carbon release being offset by regrowth of carbon capturing equivalent biomass.
Addendum: On March 3, FERC issued an Order in this proceeding. FERC found, among other things, that they were not persuaded that Morongo Transmission should receive an RTO Adder of 100 bp and provided the 50 bp RTO Adder typically granted for RTO membership.
In Docket No. ER21-669, on December 16, 2020, Morongo Transmission LLC (“Morongo”) requested a transmission formula rate for its investment in the West of Devers Upgrade Project (the “Project”), currently being developed by Southern California Edison Company (“SCE”). Morongo has entered into an agreement with SCE that provides Morongo with an option to enter a 30-year lease of a percentage of the transfer capability of a segment of the Project (the “Option”). To fund its interest, Morongo may choose to invest up to the greater of $400 million or 50% of the final estimated cost of the Project, in the
form of prepaid rent. The amount that Morongo chooses to invest will determine the amount of transfer capability that Morongo will turn over to the CAISO’s operational control. Most of the interests in Morongo are owned by the Morongo Band of Mission Indians (“Morongo Band”), a federally recognized American Indian Tribe exercising jurisdiction over lands within the boundaries of the Morongo Reservation (“Reservation”). The remainder of Morongo is owned by Coachella Partners LLC, a limited liability company formed for the purposes of facilitating and investing in the Project. Axium Coachella Holdings LLC (“Axium Coachella”), a Delaware limited liability company, owns 100% of the membership interests in Coachella Partners. Axium Coachella is a direct, wholly owned subsidiary of AxInfra US LP (“AxInfra”). AxInfra, an investment fund focused on infrastructure investments in the United States, is managed by Axium Infrastructure US Inc. (“Axium US”), acting on behalf of AxInfra’ s general partner, Axium US Partner LLC.
The Project will provide for the transmission of electricity between the Devers Substation (located
near Palm Springs, California), El Casco Substation (located near the City of Calimesa in Riverside
County, California), Vista Substation (located in the City of Grand Terrace, California), and San
Bernardino Substation (in San Bernardino County, California). The Project will allow SCE to
increase the power transfer capability of current transmission facilities by approximately 3,200
MW – from approximately 1,600 MW to 4,800 MW – thereby enabling the deliverability of
electrical power from renewable generation sources that require the Project to deliver energy to
California load, and improving the transfer capability for resource adequacy imports.
The Project is replacing existing transmission facilities, portions of which cross the Reservation.
At the time SCE began planning for the Project, it occupied a 300-foot wide, six-mile expired
right-of-way on the Reservation, pursuant to temporary licenses issued by the Morongo Band.
SCE requested that the Morongo Band agree to grant to SCE an expanded 50-year, six-mile,
right-of-way in the existing transmission corridor through the Reservation to construct the Project.
SCE lacked the ability to condemn the right-of-way because states (and therefore utilities) do not
have eminent domain authority on Indian reservations. As a means of resolving the impasse, the Morongo Band offered to agree to the grant a right-of-way through the Reservation on the existing transmission corridor if SCE gave Morongo (newly formed for purposes of the parties’ agreement) an option to finance a portion of the Project upon completion. This creative solution was modeled on the then-recently entered agreement between San Diego Gas and Electric and Citizens Energy for the Sunrise Powerlink Transmission Project. Morongo would hold an Option to lease a percentage of the transfer capability of the Project (the “Lease”). The agreement on the Option and the Lease by SCE and Morongo is the first of its kind between a transmission utility and an Indian tribe.
Morongo’s Transmission Revenue Requirement is established on a formulaic basis and is the sum of two parts: (1) Capital Costs and (2) Operating Costs. The annual Capital Cost revenue requirement is calculated based on Morongo’s annual capital costs of leasing the Transfer Capability, with the rate for annual capital cost recovery being fixed, and the sum of that fixed rate plus Morongo’s share of property taxes can be no higher than the rate that SCE would charge for Morongo’s interest in the Project absent Morongo’s participation in the Project. The annual Capital Cost revenue requirement will be
fixed and levelized for the 30-year term of the lease. The annual Capital Cost revenue requirement incorporates a hypothetical capital structure of 50% equity and 50% debt, previously allowed by FERC pursuant to a 2014 Declaratory Order. The operating costs included in the annual revenue requirement are those operating costs directly attributable to Morongo’s Transfer Capability for the Project. The operating costs include those costs SCE bills to Morongo as well as those costs Morongo incurs directly by managing and administering its Transfer Capability (“Operating Costs”). Morongo is proposing that the Operating Costs be billed to the CAISO on an estimated basis, with an annual after-the-fact true-up to actual costs.
Morongo proposes to use SCE’s current authorized return on equity of 10.3% as a proxy for Morongo’s base return on equity. Morongo requests that FERC grant a 100-basis point adder to Morongo’s base return on equity, based upon Morongo’s commitment to become a new member of CAISO and transfer
operational control of its transfer capability under the Lease to CAISO once the Project has been
placed in service and Morongo has exercised its Option and closed on the Lease. Morongo asserts that the 100-basis point RTO participation incentive is just and reasonable based upon FERC’s policy encouraging new investment in transmission infrastructure, benefits from Morongo’s participation in the Project and membership in the CAISO and risks specific to Morongo Transmission by comparison to SCE and other diversified transmission utilities. In Order No. 679, Morongo states that FERC did not make a finding on the appropriate size or duration of the RTO Participation incentive, with the result that transmission utilities seek, on a case-by-case basis, an RTO participation adder of a specific size. Additionally, Morongo requested a 100-basis point adder for joining the CAISO as FERC has proposed a standard RTO Participation adder of 100 basis points in its current NOPR.
This case was before FERC for review an audit finding in Docket No. FA15-16 related to AFUDC for a natural gas pipeline. FERC found that Dominion Energy Transmission’s (DETI) calculation of AFUDC is not consistent with FERC’s accounting regulations. FERC found that it was undisputed that from 2008 to the present period covered by the Audit Report, DETI’s short-term debt balances exceeded DETI’s CWIP balances. Per the regulations in GPI No. 3(17)(b) (like those for electric utilities), DETI should have calculated its AFUDC rate using only weighted average short-term debt rates. However, DETI instead used the consolidated balances for short-term debt and CWIP maintained by its parent entity, Dominion Energy Gas Holdings, which covered numerous subsidiaries in addition to DETI. DETI determined that, for these consolidated balances, the consolidated CWIP monthly balances exceeded consolidated short-term debt, and thus DETI applied cost rates for long-term debt, preferred stock, and common equity to a portion of its CWIP to arrive at an AFUDC rate. The AFUDC rate, determined by DETI, was above the AFUDC rate allowed under the Commission’s regulations, leading to over capitalization of AFUDC, from 2008 through 2015, by approximately $54.1 million in audit staff’s estimation (although DETI estimates the impact to be approximately $48 million). FERC found that nothing in the text of the Commission’s regulations found at GPI No. 3(17), or in Order No. 561, authorized DETI to exclude the fact that its book balances of short-term debt exceeded its book balances of CWIP. Therefore, per GPI No. 3(17), DETI’s AFUDC rate should have been calculated without reference to cost rates for long-term debt, preferred stock, or common equity. The amount of AFUDC calculated by DETI exceeded the maximum amount prescribed by the AFUDC formula, yet at no time did DETI seek authorization from FERC, as required by GPI No. 3(17), to exceed that maximum amount. As FERC held in another proceeding in which a regulated entity, without seeking its authorization, excluded its short-term debt balances from its AFUDC rate calculation: “[O]ur regulations are clear and explicit that short-term debt should be included in the calculation of AFUDC rates …. It was and is [the regulated entity’s] obligation to justify a departure, i.e., a waiver of those regulations and that policy, and [it] did not and has not done so.”
 Otter Tail Power Co., 119 FERC ¶ 61,217, at P 15 (2007).
FERC Denies AEP's request to classify its middle creek energy storage project as a transmission asset
On July 22, 2020, in EL20-58, AEP requested FERC to determine that its Middle Creek energy storage project (Middle Creek) was eligible for cost-of-service recovery through AEP’s transmission formula rates, and specifically through the transmission accounts designated for such projects in Order No. 784. AEP asserts that Middle Creek is a transmission asset that has undergone full review through the PJM stakeholder process, and AEP does not propose that the project will participate in wholesale energy or capacity markets or provide ancillary services, and thus AEP does not propose to recover market-based revenues through those markets. Middle Creek is an innovative battery storage project that will provide an efficient and cost-effective solution to address outages on the AEP transmission system. AEP carefully analyzed the cause of those outages and potential alternative solutions, including tearing down and rebuilding 14 miles of transmission line segments, and determined that a properly sized battery storage solution would reduce customer exposure to the transmission outages at far less than the cost of the transmission rebuild project. The project went through the appropriate PJM stakeholder process, wherein it underwent the same review process as would a traditional wires solution. As such, AEP asserts that the Middle Creek Project is appropriately deemed a transmission project, consistent with the definition of a Transmission Facility under the PJM Tariff.
FERC determines whether an energy storage facility is a transmission asset on case-by-case basis by determining if the storage facility performs a transmission function. In its Order dated December 21, 2020, FERC found that the Middle Creek Project is not appropriately classified as a transmission asset eligible for recovery through AEP’s transmission formula rate. FERC found that the proposed operation of the Middle Creek Project, whereby the proposed battery storage device only discharges electric energy to serve retail load at the Middle Creek substation to which it is connected while configured in an islanding mode, demonstrates that it would serve a function more analogous to a backup generator serving a subset of retail customers than that of a transmission facility when restoring Middle Creek load. AEP stated that the Middle Creek substation was designed to be served by two transmission lines, each line from one of two transmission substations. While AEP asserted that the Middle Creek Project would “continue that arrangement by providing ‘looped-equivalent’ transmission service,” FERC was not persuaded that the Middle Creek Project would perform a transmission function or that displacing the need for a looped transmission facility necessarily provides for “looped-equivalent” transmission service. Although AEP asserts that the Middle Creek Project underwent the same review process as a traditional wires solution, FERC found that displacing the need for a transmission facility in a transmission planning process, such as through the Attachment M-3 process, in and of itself is insufficient to determine that a storage facility performs a transmission function. Rather, performance of a transmission function is a necessary consideration in determining whether a storage facility can be classified as transmission. Further, as AEP describes the Middle Creek Project in the Petition, the Middle Creek Project would not support transmission of electricity in interstate commerce, given the configuration of the facility when it will be called upon to discharge electricity. As stated by AEP, the Middle Creek Project will be configured to be in stand-by mode so that it does not inject power to the grid. When there is an outage on the transmission line to the Middle Creek substation, AEP will “move to ensure that the isolating breakers at the Middle Creek [s]ubstation (on the transformer high side) and Prestonsburg Station are open.” Only then will the battery discharge energy to the Middle Creek Substation in an islanding mode. Accordingly, the Middle Creek Project will never discharge energy while the Middle Creek substation is connected to the transmission system, and therefore transmission of energy in interstate commerce will not occur.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.