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.
Accounting for Excess ADIT for Energy Companies with Negotiated and recourse rates
In its Order on Rehearing issued on December 4, 2020, in Docket No. AC19-95, FERC reaffirmed its requirement that Alliance Pipeline L.P. should disclose in the Notes to its Financial Statements the full excess ADIT that would be recorded absent its determination that it is not probable that all the amounts would be returned to customers. As stated in an Order dated October 2020, FERC’s regulations and the 1993 Accounting Guidance do not specifically address the application of FERC’s policies in the context of a pipeline with both negotiated rates and recourse rates. Notwithstanding, FERC found that its regulations require pipelines to record on their books excess ADIT balances in Account 254 if such excess ADIT balances are probable of being returned to customers.
A natural gas pipeline charging negotiated rates is also required to develop, and authorized to charge, a recourse rate, which includes excess ADIT balances as a cost component. Considering this, FERC directed Alliance to, at the minimum, disclose its excess ADIT balances in the Notes to Financial Statements to provide information that is useful for the development of its future rates to fulfill a separate, regulatory need. FERC found that its Form No. 2 provides cost and revenue data that aids in evaluating the justness and reasonableness of rates in a ratemaking proceeding. FERC Form No. 2 also serves as a ready source of public information to assess on an ongoing basis the justness and reasonableness of a pipeline’s rates. FERC found that by directing Alliance to provide the full excess ADIT in its Notes to Financial Statements, shippers will benefit from the improved transparency, which will help them to assess whether to pursue a rate challenge.
On November 19, 2020, FERC rejected two unilateral reactive power revenue requirement settlements. Both were neither supported nor opposed by the parties, but Trial Staff opposed both. In the Allegheny case, FERC Trial Staff opposed the settlement because they were not provided information to determine if the reactive power revenue requirement was reasonable. Hearing procedures have been resumed for both cases. The Allegany case is the first litigated reactive power revenue requirement case and presents FERC with an opportunity to address how to apply the AEP methodology to wind resources.
Lawrenceburg Power, LLC, Docket No. ER18-2497-002. The order addresses an offer of settlement that was unilaterally filed by Lawrenceburg Power regarding its reactive power rates. The settlement was neither supported nor opposed by any parties but was opposed by FERC Trial Staff. The order finds that the settlement has not been shown to be fair and reasonable and in the public interest. The order remands the proceeding to the Chief Administrative Law Judge to resume hearing procedures.
Allegheny Ridge Wind Farm, LLC, Docket No. ER19-229-001. The order addresses an offer of settlement that was unilaterally filed by Allegheny Ridge Wind Farm regarding its reactive power rates. The settlement was neither supported nor opposed by any parties but was opposed by Trial Staff. The order finds that the settlement has not been shown to be fair and reasonable and in the public interest, and it remands the proceeding to the Chief Administrative Law Judge to resume hearing procedures.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.