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.
blog on the This blog is a follow-up to the FERC Order dated August 17, 2020, in Docket No. ER20-1068, where FERC accepted a request by The Dayton Power and Light (DP&L) for an RTO Adder, yet suspended it for a five month period, subject to refund and the outcome of a paper hearing to explore whether DP&L has shown that its participation in PJM or another RTO is voluntary or if such participation is mandated by Ohio law. On September 16, in this docket, PJM requested clarification of the FERC August 17, 2020 Order that the Order should not be construed as a holding that “voluntariness” is the sole criterion by which to judge the appropriateness of DP&L’s RTO Adder request. PJM states that although voluntariness is relevant to the analysis, FERC should clarify that its investigation of this singular issued is not dispositive of the question of the appropriateness of the RTO Adder for DP&L going forward - that FERC should make it clear that it is keeping its options open pending receipt of a more fulsome record and is not substituting a sole criterion analysis in the place of the “case-by-case” RTO Adder eligibility analysis required by Order 679.
The New England transmission owners (NETOs) have had four challenges since 2011 to the base ROE. The first case was decided by FERC in 2014. The decision was challenged in the DC Court of Appeals, which in 2017 vacated the FERC decision. FERC has made no decisions in the three subsequent base ROE cases. Once the Court vacated the first case decision , the NETOs filed a compliance filing with FERC in October 2017 to reinstate the base ROE that was in effect prior to the FERC decision in the first ROE case. FERC rejected the compliance filing and ordered the NETOs to maintain the base ROE which FERC determined in the first base ROE case, even though the Court had vacated that decision. The NETOs requested rehearing in late 2017, after which FERC issued a tolling order that purported to grant rehearing until FERC issued a further order on rehearing. The DC Court of Appeals recently issued an opinion holding that FERC’s use of tolling orders to afford itself more time to act on rehearing did not comport with the Natural Gas Act (and thus the Federal Power Act). Based upon the Court’s tolling order opinion, the NETOs now deem their request for rehearing on the rejected compliance filing denied. As a result, on September 9, 2020, the NETOs petitioned the Court for review of FERC’s Order rejecting their 2017 compliance filing.
In Docket AC20-149, Interstate Power and Light (IPL) requested FERC’s permission to record the net book value of retiring electric analog meters in Account 182.2, Unrecovered Plant and Regulatory Study Costs, and to amortize the balance in Account 182.2 to Account 407 through February 2028, consistent with an Iowa retail rate case decision which called for a return of but not a return on the undepreciated analog meter investment of $39 M. IPL wants alignment between retail and FERC rates. Between 2017 and 2019, IPL deployed Advanced Metering Infrastructure (“AMI”) to its retail service territory. To generate the greatest long-term benefits of the AMI system, the existing analog metering system needed to be replaced in a relatively short period of time, leaving some remaining undepreciated investment. FERC’s Acting Chief Accountant and Director approved IPL’s request.
In an Order issued August 28, 2020 in ER20-2472 and ER20-1726, FERC has reaffirmed its position on the inclusion of prepaid pension costs in the rate base of transmission formula rates. FERC stated that a prepaid pension cost is the amount by which cumulative contributions to a pension trust exceed
cumulative pension expenses. FERC further stated that, consistent with this definition, the appropriate way to calculate prepaid pension costs includable in rate base would be to calculate the cumulative differences between each year’s pension contributions and pension expenses.
In its April 2015 filing that led to Opinion No. 570, Entergy asserted that its proposal to use a different formula (i.e., Funded Status minus Unrecognized Gains/ Losses) to calculate prepaid pension costs instead of the Commission’s prescribed formula of annual pension contributions minus annual pension expenses reached the same result as FERC’s prescribed formula. In Opinion No. 570, FERC had previously found that Entergy had not adequately supported its claim, nor had it adequately explained what comprises the different components of the formula and why it is appropriate to use those components to calculate prepaid pension costs. FERC therefore rejected Entergy’s proposed formula rate template line item “without prejudice to Entergy making a future filing that adequately demonstrates that its
proposal, including its methodology for calculating prepaid and accrued pension costs, is just and reasonable.”
In the August Order, FERC approved Entergy’s new proposal as FERC found that it adequately addresses the concerns in Opinion No. 570 and that Entergy has met its burden to demonstrate that its proposed formula rate line item is just and reasonable. FERC found that Entergy has made a sufficient showing, through its explanations as well as its mathematical proof, that its alternative formula leads to the same result as the formula based on cumulative differences between each year’s contributions and expenses. Though FERC has set forth a formula for calculating prepaid pension costs, alternative formulas may also be just and reasonable if adequately supported and if their sponsors can prove that the alternative yields the same result as the formula laid out in Opinion No. 570. We also find that Entergy has sufficiently demonstrated, through its explanations and responses, what comprises the different components of the formula.
On July 22, 2020, in EL20-58, AEP requested FERC to determine that its Middle Creek energy storage project (Middle Creek) is 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.
On August 17, 2020, in Docket No. ER20-1068, FERC granted the Dayton Power and Light Company the CWIP and Abandonment incentives for a suite of projects resulting from the PJM planning process or subject to Ohio state siting approval. In addition, Dayton had requested the 50-basis point RTO Adder as it is a member of the PJM RTO and has turned functional control of its transmission assets to PJM. FERC accepted the RTO Adder part of request and suspended it for a five month period, subject to refund and the outcome of a paper hearing to explore whether Dayton has shown that its participation in PJM or another RTO is voluntary, as required for it to be entitled to the adder, or if such participation is mandated by Ohio law. Initial responses to the questions in the Appendix (see below) of this order are due within 60 days of the date of this order and reply comments to the initial responses are due within 30 days of the initial responses. FERC requested that parties respond to the following two questions:
1. Is there an arrangement under which Dayton could withdraw from an RTO and comply with the Ohio law, while not being eligible for an RTO Participation Adder? If so, please describe that alternative arrangement. If not, please explain why not.
2. Explain how any alternative arrangement identified in response to Question 1 would comply with the Ohio Revised Code section 4928.12, but would not at the same time qualify for incentives for joining a Transmission Organization under section 35.35(e) of the Commission’s regulations, 18 C.F.R § 35.35(e) (2019). As part of your answer, please: (1) explain why such arrangement would not qualify for an incentive under section 35.35(e) of the Commission’s regulations; and (2) address each of the 9 requirements for such an arrangement specified in Ohio Revised Code section 4928.12(B) and explain how the arrangement satisfies each such requirement.
Commissioner Glick dissented in part because he felt that the record FERC is clear that Ohio law requires The Dayton Power and Light Company (Dayton) to be a member of a Transmission Organization. As a result, there is nothing for the Commission to incentivize by awarding an additional ROE for Transmission Organization membership. Consistent with Commission precedent, that alone should be more than enough for us to reject this aspect of Dayton’s filing. Commissioner Danly concurred in the ruling on the RTO Participation Adder, even though the issue set for hearing on the RTO Participation Adder is a legal question that likely could be resolved without a hearing. Although he would have ruled on that question now, he acknowledged that it is within the Commission’s discretion to set the matter for hearing instead. Further, if he were to join in Commissioner Glick’s dissent, that would cause a 2-2 split on The Dayton Power and Light Company’s request for the RTO Participation Adder. It would then go into effect by operation of law without further consideration of the legal question being set for hearing. By concurring in the decision to set the RTO Participation Adder for hearing, that outcome was avoided.
On August 20, 2020 in Docket No. EL20-65, the NYISO requested that FERC confirm that the NY Transmission Owners (NYTOs) have a right of first refusal to build, own, and recover the costs of upgrades to their existing transmission facilities and that this right encompasses upgrades proposed as part of another Developer’s transmission project that is selected by the NYISO to be included in its regional plan. The NYISO also requested that FERC confirm that if a NYTO exercises its right to build, own, and recover the costs of an upgrade that is included in another Developer’s proposed transmission solution that was selected by the NYISO, the NYTO should be treated under existing OATT provisions as the Developer for the upgrade portion of the project, except that the voluntary cost containment provisions would not apply. Finally, the NYISO requested that FERC clarify two specific points regarding the definition of “upgrade.” The OATT includes the Order No. 1000-A definition, which distinguishes an upgrade that may be subject to a right of first refusal from an entirely new transmission facility that must be subject to competition. However, the distinction between an upgrade and an entirely new transmission facility is not always clear and the ambiguity is expected to result in disputes given the likelihood that transmission projects addressing needs in New York will involve modifications to existing transmission facilities within existing rights of way. The NYISO requested that FERC clarify two specific points – would a new transmission facility that requires the retirement and decommissioning of a NYTOs existing transmission facilities and that connects to the transmission system in a different configuration constitute an upgrade and, if the facility would be treated as a new transmission facility, would the retirement or decommissioning of the existing transmission facilities require the agreement of the NYTO that owns the facilities or a state regulatory or court ruling authorizing the retirement or decommissioning?
In June 2020, FERC Staff issued a report on barriers and opportunities for high voltage transmission to the Committees on Appropriations of Both Houses of Congress. Staff concludes that high voltage transmission can improve the reliability and resilience of the transmission system by allowing utilities to share generating resources, enhance the stability of the existing transmission system, aid with restoration and recovery after an event, and improve frequency response and ancillary services throughout the existing system. High voltage transmission also provides greater access to location-constrained resources in support of renewable resource goals. It also offers opportunities to meet federal, state and local policy goals. Staff found that while transmission development opportunities exist, there are also barriers which make development of high voltage transmission challenging. For instance, siting of high voltage transmission, generally an area of state jurisdiction, requires navigating each state process or multiple state processes for an interstate high voltage transmission facility. Various other authorizations and reviews are also generally required at the federal, state, and local levels. Additionally, the time required to develop a high voltage transmission facility that meets mandatory Reliability Standards, maximizes system benefits, and strikes a balance among interested stakeholders (including states) can be in excess of a decade. Specific to the nation’s transportation corridors, there are several federal and state actions intended to create opportunities for energy infrastructure development, including high voltage transmission, in these corridors. However, future transmission development in existing transportation corridors may be restricted by routing limitations, including state and local prohibitions and restrictions, and safety and technical considerations.
Pacific Gas and Electric requests abandonment incentive for work related to two projects awarded to LS Power
On August 6, 2020, in Docket No. EL20-60, Pacific Gas and Electric Company (“PG&E”) filed for a Petition for Declaratory Order (“Petition”) for 100% recovery of prudently-incurred abandoned plant costs (if abandoned for reasons outside the control of PG&E) for PG&E’s portion of two significant reliability-driven transmission projects approved in CAISO’s 2018-2019 Transmission Plan: (1) the Gates 500 kV Dynamic Reactive Support Project (“Gates Project”) and (2) the Round Mountain 500 kV Area Dynamic Reactive Support Project (“Round Mountain Project”) (collectively “Projects”). Under its competitive solicitation process, the CAISO selected LS Power Grid California, LLC (“LS Power Grid”) as the Project Sponsor for the Gates Project on January 17, 2020, and the Round Mountain Project on February 28, 2020. As the incumbent transmission owner, PG&E is required to complete significant supporting work for the Projects. For the Gates Project, PG&E is responsible for all system upgrades, including telecommunications and protection system upgrades using advanced fiber optic technology and for all equipment installation to connect the Gates voltage control equipment to the Gates 500 kV bus on the PG&E side of the point of change of ownership switch. For the Round Mountain Project, PG&E will be responsible for various project specific telecommunications and protective system upgrades at both the target substations and adjacent substations. For example, new tripping schemes will need to be installed to account for voltage support equipment operations in non-normal system configurations. This work is extensive, often entails significant work at other, more remote, substations and will not be known with certainty until much later in the project design process as detailed design comes to completion. PG&E asserts that since LS Power Grid received the abandonment incentive for these two projects, PG&E is entitled to the abandonment incentive for its related investments as PG&E faces the same risk and challenges as LS Power Grid. Finally, the substantial cost, long-lead time for equipment, risk of cost escalation, and risk of a shortage in skilled labor are all risk factors that could lead to the cancellation of one or both projects, exposing PG&E to the risk of unrecovered costs without the Abandoned Plant Incentive.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.