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.
FERC Rejects Putting End of Life transmission Projects under PJM's RTEP Transmission planning process
In ER20-2308, PJM filed a proposal developed by PJM Stakeholders to provide a structure for end-of-life (EOL)-driven transmission projects to be reviewed and developed under PJM’s Regional Transmission Expansion Plan (RTEP). The Proposal would: (1) obligate PJM TOs to submit a binding notification to PJM of facilities that will reach their EOL within six years; (2) require PJM TOs to develop an EOL program, including criteria, for facilities approaching EOL status; (3) require PJM TOs to provide PJM a 10-year, forward-looking list of facilities’ EOL Conditions; (4) exclude the planning of EOL facilities from the RTEP reliability exemption for transmission facilities under 200 kV; and (5) remove the planning of EOL facilities from Attachment M-3 and include all EOL facilities under the PJM RTEP planning process. This proposal was opposed by the PJM TOs.
FERC rejected the Proposal, finding that, under applicable agreements, the PJM TOs retain the rights to maintain their transmission facilities and when facilities should be retired, and that PJM’s authority extended to directing the operation of the transmission facilities, administering the PJM OATT, and administering the RTEP process. FERC also found that a transmission project to address EOL Conditions that is limited to replacing existing equipment, or that involves only an incidental increase in transmission capacity, does not involve expansion or enhancement of the regional transmission system. Such a replacement project does not fall under regional transmission planning under the PJM Operating Agreement as it relates solely to maintenance of existing facilities, and it does not “expand” or “enhance” the PJM grid. Transmission projects to address an EOL Condition that replace existing equipment involve decisions regarding retirement and maintenance of existing equipment, a responsibility that the PJM TOs specifically retained.
In Docket Nos. PL-20-3 and RM20-7, FERC proposed revisions to its policy statement for natural gas index developers and change reporting requirements for those who report prices to those index developers. The changes proposed are intended to support the formation of physical natural gas price indices.
A natural gas price index is a weighted average price derived from a set of fixed-price natural gas transactions within distinct geographical boundaries that market participants voluntarily report to a price index developer. Natural gas price indices play a vital role in the energy industry as they are used to price billions of dollars of natural gas and electricity transactions annually in both the physical and financial markets. Natural gas markets depend on robust and accurate indices in order to ensure just and reasonable prices. Natural gas price indices serve as a proxy for the locational cost of natural gas in the daily and monthly trading markets, as many market participants reference natural gas index prices in their physical and financial transactions. Interstate natural gas pipelines, public utilities, Independent System Operators (ISOs), and Regional Transmission Organizations (RTOs) reference natural gas price indices in their tariffs for various terms and conditions of service. State commissions also use natural gas price indices as benchmarks when reviewing the prudence of natural gas or electricity purchases. Finally, many natural gas financial derivative contracts that are used in hedging and speculation settle against natural gas price indices.
To address the relative low number of fixed price volumes reported to index developers and the potential effects on market liquidity, FERC proposed several revisions to the Commission’s price index policy set forth in its prior Policy Statement. The revisions would reduce perceived reporting burdens, encourage more reporting, and provide greater transparency into the natural gas price formation process. As a result, the revisions would increase confidence in the accuracy and reliability of wholesale natural gas prices.
First, FERC proposed to allow data providers to report either their non-index based next- day natural gas transactions, their non-index based next-month natural gas transactions, or both types of transactions, to price index developers. Second, FERC proposed to allow data providers to self-audit the transactions they provide to price index developers on a biennial basis. Currently, data providers are required to perform a self-audit on an annual basis. The revisions are aimed at reducing the burden associated with price reporting in the hope that it may lead to additional market participants reporting their transactions to index developers. In addition, FERC proposed to encourage data providers to report to all available Commission-approved price index developers.
FERC also proposed two revisions to increase transparency in the natural gas price formation process. It proposed to modify the Commission’s standards to remain an approved natural gas price index developer such that price index developers should: (1) indicate whether a published index price is assessed in their published indices and (2) obtain re-approval in order for their indices to continue to be included in FERC-jurisdictional tariffs. Finally, FERC proposed to clarify the review period for assessing the liquidity of price indices submitted for reference in FERC-jurisdictional tariffs.
FERC issued a Notice of Proposed Rulemaking (NOPR) in Docket RM-21-3 that would allow public utilities to request incentives for certain cybersecurity investments that go above and beyond the requirements of the North American Electric Reliability Corporation, or NERC, Critical Infrastructure Protection Reliability Standards, the CIP Reliability Standards. The proposed cybersecurity incentives framework encourages public utilities to undertake cybersecurity investments on a voluntary basis that are above and beyond the requirements of the mandatory CIP Reliability Standards and, thereby, better ensure secure service for customers. This approach would incent a public utility to adopt cybersecurity practices that would not only better protect its own systems but also improve the cybersecurity of the Bulk-Power System. The NOPR includes two incentive approaches:
The first approach, the NERC CIP Incentives Approach, would allow a public utility to receive incentive rate treatment for voluntarily applying identified CIP Reliability Standards to facilities that are not currently subject to those requirements.
The second approach would allow a public utility to receive incentive rate treatment for implementing certain security controls included in the Cybersecurity Framework developed by the National Institute of Standards and Technology, the NIST Framework. This is the NIST Framework Approach. The NIST Framework includes many types of security controls; however, the NOPR proposes to initially only consider one type of security controls, automated and continuous monitoring, as eligible for an incentive under this approach.
The NOPR would allow a public utility to request incentives using any combination of the two proposed approaches.
Under the NOPR, a public utility that makes cybersecurity investments consistent with the two approaches that we have described would be eligible for one of the following two types of incentives:
The first incentive would apply a 200 basis-point adder to the return on equity for eligible cybersecurity capital investments and is referred to as the Cybersecurity ROE Incentive.
Alternatively, the second incentive would allow a public utility to seek deferred cost recovery for certain expenses related to cybersecurity investments and is referred to as the Regulatory Asset Incentive.
Finally, the NOPR describes the showings that a public utility would have to make to receive either incentive and would require an annual informational filing.
Initial comments are due 60 days (mid-February 2021), and reply comments 90 days (mid-March 2021), after the date of publication in the Federal Register.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.