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. 
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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. 
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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. 

​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.