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.
Baltimore Gas and Electric Requests alignment of the Annual true-up adjustment for its transmission formula rate
On October 26, 2020, Baltimore Gas and Electric (BGE), a subsidiary of Exelon, filed in Docket No. ER21-214 revisions to its transmission formula rate to align calendar year revenue and revenue requirement in its Projected Annual Transmission Revenue Requirement and in its Annual True-up Adjustment. To accomplish this alignment, BGE seeks to adjust the true-up mechanism in its Formula Rate to: (1) use actual revenues, rather than projected revenues, for a 12-month period as the basis for the true-up; and (2) true-up those actual revenues for a given January to December time period to actual costs for that same January to December time period, instead of truing up revenue projections for a June to May time period to actual costs for the January to December time period, as is done in BGE’s current transmission formula rate. This timing adjustment revision is consistent with FERC precedent and have been implemented for several utilities, including Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company (all Exelon subsidiaries).
The filing also revises the method for developing the forecasted revenues for the upcoming year, which are used to establish BGE’s projected revenue requirement – the basis for its transmission rates. Under the new methodology, BGE will use projected values for plant, accumulated depreciation, depreciation and amortization expense, other income tax adjustment expense, and accumulated deferred income taxes (“ADIT”) for the upcoming year when developing its projected transmission revenue requirements. All rate base items in the projected and true-up revenue requirements will also be calculated using the average of 13 monthly balances with the exception of ADIT, which will use a simple average.6 Non-plant related rate base items and capital structure will continue to use historical data; however, this data will be 13-month average balances as opposed to year-end balances as done with the current Formula Rate. To adhere to tax normalization rules, ADIT would reflect the application of proration rules. Historical data will still be used for non-plant related rate base components of the projected revenue requirement (e.g., prepayments, reserves, materials and supplies), other expenses (e.g., Operating & Maintenance expenses and Taxes Other Than Income Taxes) and capital structure, as these items tend to have less year-to-year variability compared to plant-related items.
michigan electric transmission requests recovery in its transmission formula rate for up to $15 m for ev charging pilot
On November 16, 2020, in ER21-424, Michigan Electric Company (MET) applied to FERC for authorization to recover in electric transmission rates: (1) up to $15 million in costs associated with the construction of new transmission facilities and the deployment of advanced technology to support the development of new electric vehicle (EV) infrastructure in the State of Michigan (EV Infrastructure Pilot Project or Pilot Project); and (2) recovery of 100 percent of abandoned plant costs in the event the EV Infrastructure Pilot Project is abandoned for reasons beyond MET’s control. MET’s EV Infrastructure Pilot Project will facilitate the development and deployment of publicly accessible Direct Current Fast-Charging (DCFC) EV stations to serve long-haul medium- and heavy-duty commercial vehicles, trucks, and buses, and will provide data and information needed to assess how electrification trends and the deployment of EV infrastructure may impact the operation and reliability of the interstate transmission grid regulated by FERC. METC can already recover the costs of the Pilot Project through its existing formula rate. However, the 2009 Smart Grid Policy Statement allows applicants like METC to submit a section 205 filing to provide “the assurance of cost recovery” and to mitigate against the risk of “future review and challenge.”
On November 19, 2020, in EL14-12, FERC issued an Order on Rehearing regarding the MISO TO’s ROE. FERC determined:
On October 15, 2020, FERC issued Opinion 572 in Docket No. ER16-2320 on Pacific Gas and Electric’s (PG&E) 2018 electric transmission rate. In this order, among other things, FERC directed further briefing regarding PG&E’s ROE (initial briefs shall be due in 60 days, with responses due 30 days later).
PG&E requested an expedited decision from FERC on its request in Docket No. AC19-122 whereby PG&E proposed to determine its AFUDC rate in a manner that excludes certain liability provisions required by GAAP that do not have an impact on cash available to fund construction. Specifically, PG&E had requested the Commission’s authorization to exclude from the AFUDC rate formula calculation the 2017 Northern California Wildfires and the 2018 Camp Fire contingent liabilities, net of accrued insurance proceeds and accrued tax benefits (and any future regulatory asset offset), from its equity balance (i.e., capital structure calculation). On October 15, 2020, PG&E filed an Offer of Settlement and Stipulation (Settlement) in its Formula Rate Proceedings (ER19-13, ER19-1816 and ER20-2265) which included adjustments to PG&E’s regulatory capital structure used in its Formula Rate. In the Settlement, the Parties agreed to a fixed capital structure for use in the Formula Rate with common stock being fixed at 49.75%, preferred stock being fixed at 0.5%, and long-term debt being fixed at 49.75%. The Parties also agreed that this capital structure should be used in PG&E’s AFUDC calculation for the permanent capital component of the AFUDC rate. As a result, PG&E revised its request in Docket No. AC19-122 to reflect the terms of the settlement as to how the AFUDC calculation adjustment to the permanent capital component (i.e., non short-term debt) of the AFUDC rate be determined. PG&E requested that these changes apply to AFUDC calculations effective as of May 1, 2019 through June 30, 2020 as the 2017 Northern California Wildfires and the 2018 Camp Fire contingent liabilities were paid upon PG&E’s emergence from bankruptcy on July 1, 2020.
On October 15, 2029, in Docket No. ER20-1783, FERC approved a request by NEET MidAtlantic Indiana for a formula rate that accommodates its acquisition of certain transmission facilities from Commonwealth Edison Company of Indiana, Inc. (ComEd) and rejected its request to establish a regulatory asset for transaction costs related to the acquisition. FERC approved the tariff changes to become effective upon the date NEET MidAtlantic Indiana becomes a transmission-owning member in PJM. FERC denied NEET MidAtlantic Indiana’s request for pre-approval to record the transaction costs as regulatory assets as the transaction costs at issue here are not the type of incentives, such as formation and pre-commercial costs related to competition for transmission enhancements as part of the RTEP process, that the Commission has previously found further the policy goal of facilitating the participation of nonincumbent transmission developers in transmission planning processes, thereby encouraging competition. Rather these costs are associated with the acquisition of existing transmission assets. FERC’s policy is to accept acquisition adjustments in rate base, and thus allow their recovery, only if utility can show that “the investment decision is prudent and if it can demonstrate that the acquisition provides measurable benefits to ratepayers.” To recover such acquisition adjustments, the utility must show specific, tangible, non-speculative, quantifiable benefits in monetary terms, which NEET MidAtlantic Indiana did not do.
By Order dated March 27, 2020, in Docket No. ER20-276, FERC found that Prairie Power should use its actual capital structure of 19% equity and 81% debt to determine its transmission revenue requirement in its transmission formula rate rather than the hypothetical capital structure of 50% equity and 50% debt requested by Prairie Power. Prairie Power requested rehearing. In its Order on rehearing dated September 17, 2020, FERC sustained its March 27th Order, as FERC found that Prairie Power had failed to demonstrate that its situation warrants an exception to using its actual capital structure. FERC stated that two circumstances demonstrate that a capital structure is anomalous and warrants the use of a hypothetical capital structure: when “(a) the capital structure of the financing entity is not representative of the regulated [entity’s] risk profile, or (b) the capital structure is different from the capital structure approved for other [regulated entities], or if a [discounted cash flow (DCF)] analysis is performed, outside the range of the proxy group used in the DCF analysis.” With Prairie Power, the financing entity and the regulated entity are the same, and so the risk profile is identical. When evaluating the second type of circumstance, the analysis “is performed primarily to determine if the equity component of the capital structure of the financing entity (either the pipeline or its parent) is atypically high” and “‘[i]n general, FERC does not impute equity because this can over compensate the equity holder at the expense of the ratepayer.’” In addition, FERC reviewed all evidence and precedent that Prairie Power submitted – including responses to the deficiency letter regarding credit rating changes, financial metrics, and the effects of cost overruns – and concluded that Prairie Power had not justified its proposed departure from cost-based ratemaking.
Last, FERC was unpersuaded by Prairie Power’s argument that the MISO base ROE for transmission owners, as a small component of Prairie Power’s overall return due to its low percentage equity, inadequately compensates Prairie Power for its risk and thus justifies the use of a hypothetical capital structure. FERC stated that, to the extent that Prairie Power believes that its risks are not captured by the MISO transmission owners’ ROE in its actual capital structure, Prairie Power may file to request a different ROE under FPA section 205.
On September 17, 2020, in Docket No. EL20-51, FERC granted Southern California Edison (SCE) the transmission abandonment and CWIP incentives for its Riverside Project, which includes the construction of a new 230 kV substation and associated facilities; approximately 10 miles of 230 kV double-circuit transmission lines, of which approximately four miles will be placed underground; and new telecommunications equipment between the new substation and existing substations (Project). FERC granted abandonment incentive as SCE faces risks and challenges in the development of the Project, including certificates of convenience and necessity and wetland permits from the U.S. Army Corps of Engineers. FERC stated that the abandonment incentive will protect SCE, should the Project be abandoned for reasons beyond SoCal Edison’s control. If the Project is abandoned for reasons beyond SCE’s control, SCE would be required to make a filing under section 205 of the FPA to demonstrate that the costs were prudently incurred before it can recover any abandoned plant costs. In such a proceeding, abandoned plant cost recovery is available for 100% of prudently incurred project costs expended on or after the date of issuance of this order. In the event SCE seeks abandoned plant recovery for the period prior to the issuance of this order, SCE would be eligible to seek recovery of 50% of its prudently incurred costs.
FERC granted the CWIP Incentive as FERC has found that allowing companies to include 100% of CWIP in rate base would result in greater rate stability for customers by reducing the “rate shock” when certain large-scale transmission projects come online. With the Project expecting to cost $581 M and not expected to go into service until 2026, FERC found that granting the CWIP incentive to SCE is consistent with Order No. 679. FERC also stated in its Order that its accounting regulations provide procedures to ensure that customers will not be charged for both capitalized AFUDC and corresponding amounts of CWIP in rate base and its determination to grant SCE the CWIP Incentive is conditioned upon SCE fulfilling FERC’s requirements for CWIP inclusion for the Project in its future FPA section 205 filings.
FERC has in the past routinely acted on rehearing requests, by the 30th day, by issuing delegated orders – called tolling orders. Those orders granted rehearing for the limited purpose of extending the time allowed for the Commission to consider the merits of a rehearing request. This practice allowed the Commission time to prepare comprehensive rehearing orders addressing the concerns raised by parties in nearly all cases, but also delayed the ability of parties to seek judicial review.
On June 30, 2020, in Allegheny Defense Project v. FERC, the full D.C. Circuit issued a decision addressing the timeliness of Commission action on requests for rehearing under the Natural Gas Act. The court recognized that the Commission’s responsibilities on rehearing are complex, and also that the tolling order practice had been affirmed by the courts in decisions dating back to 1969. But the court held that, under the plain language of the Natural Gas Act, tolling orders do not amount to action on rehearing requests, and thus do not prevent rehearing requests from being “deemed” denied after 30 days. The court also highlighted the Commission’s authority, even where rehearing has been deemed denied by operation of this statutory deadline, to “modify or set aside, in whole or in part” the underlying order until the record on appeal is filed with a reviewing court.
Beginning the day after the court’s decision, the Commission began implementing changes to its rehearing practices both to expedite consideration of rehearing requests and to keep the public apprised of the status of Commission proceedings. Although the Allegheny decision arose under the Natural Gas Act, because the Federal Power Act contains identical language, the Commission is applying its post-Allegheny approach to Federal Power Act proceedings.
First, the Commission no longer issues tolling orders in cases arising under the Federal Power Act or the Natural Gas Act. Instead, where the Commission is not acting on the merits of a rehearing request by the 30-day deadline, the Office of the Secretary generally will issue one of two types of notices no earlier than the 31st day after a rehearing request is received: a Notice of Denial of Rehearing by Operation of Law, or a Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration. As the names suggest, these Notices have an important feature in common: they both acknowledge that, because the 30-day deadline in the Natural Gas Act or the Federal Power Act has passed, rehearing may be deemed denied by operation of law. The first type, a Notice of Denial of Rehearing by Operation of Law stops there and announces that the Commission does not intend to issue a merits order in response to the rehearing request. The second type of Notice – a Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration – takes an extra step. After indicating that rehearing may be deemed denied by operation of law, this Notice states the Commission’s intention to issue a further order addressing issues raised on rehearing, citing the Commission’s authority to “modify or set aside” the underlying order. Importantly, neither of these Notices rule on the rehearing request; they simply announce the status of the proceeding as a means to keep the public informed.
Second, orders on rehearing issued after the 30-day mark now reflect the exercise of the Commission’s authority to “modify or set aside, in whole or in part” a prior order until the point that the record on appeal is filed in a reviewing court. As such these orders now use the statutory terms “modify or set aside” when describing the Commission’s determinations: they use the phrase “modifying the discussion” where the Commission is providing further explanation of the underlying order but is not changing the outcome of the underlying order; and they use the phrase ‘set aside” when the Commission’s rehearing order is changing the outcome. Standardizing this terminology is intended to provide guidance to parties in discerning whether the Commission’s order is final, such that aggrieved parties may proceed to court.
Third, and finally, FERC recognizes that decisions regarding if or when to file a petition for review may be complex, particularly in cases where the 30-day deadline has passed and the rehearing request may be deemed denied by operation of law, but the Commission, through a notice, has announced its intent to issue a further merits order. In all cases, aggrieved parties continue to have 60 days after the denial by operation of law to file a petition for review.
The changes in Commission practice discussed today, among others, are intended to allow appeals of Commission orders to proceed on a complete administrative record, including a rehearing order, in a timely manner. Nonetheless, this new dynamic, where an appeal may be filed before the Commission has issued a further merits order, may present a need for earlier coordination among parties to an appeal. To facilitate that coordination, FERC Staff encourages parties contemplating an appeal, if uncertain about how to protect their right to judicial review, to seek guidance from attorneys in the Commission’s Solicitor’s Office within the Office of the General Counsel.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.