In March 2018, FERC issued a Revised Policy Statement and Opinion No. 511-C, the remand order pursuant to United Airlines (a DC Court of Appeals decision addressing income taxes for master limited partnerships (MLP)). These FERC decisions explained that United Airlines’ income tax double-recovery concern precludes an MLP pipeline from claiming an income tax allowance in its cost of service based upon two findings:
On February 21, 2019, FERC issued an Order (Docket No. RP18-922) preliminarily finding that Trailblazer Pipeline’s rates should not include an income tax allowance on that part of investor supplied capital that is from certain Private Owners as the Private Owners incur only one level of taxation, specifically a personal income tax, and the DCF ROE incorporates investor-level taxes. Thus, because the Private Owners incur only one level of taxes on Trailblazer’s income and the DCF ROE already includes a level of taxation, providing the Private Owners an income tax allowance in the Trailblazer cost of service would compensate the Private Owners twice for their single level of taxation. FERC also preliminarily found that it is proper to include an income tax allowance in Trailblazer’s rates for the part of investor supplied capital coming from its parent corporation, which does pay corporate taxes. In summary, FERC found that:
FERC emphasized that these findings, which address complex factual and policy matters, are preliminary and may change based upon subsequent evidence and argument from the ongoing administrative law judge hearing where these issues are to be fully litigated.
On April 19, 2018, FERC issued Order No. 845 which revised its pro forma Large Generator interconnection Procedures (LGIP) and pro forma Large Generator Interconnection Agreement (LGIA) to improve certainty for interconnection customers (ICs), promote more informed interconnection decisions, and enhance the interconnection process. In Order No. 845, FERC adopted ten different reforms in three general categories. First, in order to improve certainty for ICs, Order No. 845: (1) removed the limitation that ICs may only exercise the option to build a transmission provider’s (TP) interconnection facilities (sole use facilities from ownership demarcation to the point of interconnection) and stand-alone network upgrades (network upgrades that an IC may construct without affecting day-to-day operations of the transmission system) in instances when the TP cannot meet the dates proposed by the IC (with this new rule, the IC has unilateral decision-making on the option to build TP’s interconnection facilities and stand-alone network upgrades); and (2) required that TPs establish interconnection dispute resolution procedures that allow a disputing party to unilaterally seek non-binding dispute resolution. Second, to promote more informed interconnection decisions, Order No. 845: (1) required TPs to outline and make public a method for determining contingent facilities; (2) required TPs to list the specific study processes and assumptions for forming the network models used for interconnection studies; (3) revised the definition of “Generating Facility” to explicitly include electric storage resources; and (4) established reporting requirements for aggregate interconnection study performance. Third, Order No. 845 aimed to enhance the interconnection process by: (1) allowing an IC to request a level of interconnection service that is lower than its generating facility capacity; (2) requiring TPs to allow for provisional interconnection agreements that provide for limited operation of a generating facility prior to completion of the full interconnection process; (3) requiring TPs to create a process for ICs to use surplus interconnection service at existing points of interconnection; and (4) requiring TPs to set forth a procedure to allow TPs to assess and, if necessary, study an IC’s technology changes without affecting the IC’s queued position.
FERC received twelve requests for rehearing or clarification of Order No. 845. FERC granted rehearing regarding the option to build reform to: (1) require that TPs explain why they do not consider a specific network upgrade to be a stand-alone network upgrade; and (2) allow TPs to recover oversight costs related to the interconnection customer’s option to build. FERC also granted rehearing regarding the surplus interconnection service reform to explain that FERC does not intend to limit the ability of RTOs/ISOs to argue that an RTO/ISO variation from FERC’s surplus interconnection service requirements is appropriate. FERC also found that, regarding the reform for requesting interconnection service below a generating facility capacity, an IC may propose control technologies at any time in the interconnection process that it is permitted to request interconnection service below generating facility capacity. Additionally, FERC granted clarification regarding the option to build by finding that: (1) the Order No. 845 option to build provisions apply to all public utility TPs, including those that reimburse the interconnection customer for network upgrades; and (2) the option to build does not apply to stand-alone network upgrades on affected systems (another system that is affected by the interconnection). FERC also granted clarification with regard to transparency regarding study models and assumptions to find that: (1) TPs may use FERC’s critical energy/electric infrastructure information (CEII) regulations as a model for evaluating entities that request network model information and assumptions; and (2) the phrase “current system conditions” does not require TPs to maintain network models that reflect current real-time operating conditions of the TP’s system. Regarding the interconnection study deadlines reform, FERC granted clarification that the date for measuring study performance metrics and the reporting requirements do not require TPs to post 2017 interconnection study metrics – the reporting requirements will begin in 2020. Regarding requesting interconnection service below generating facility capacity, FERC granted clarification that a TP must provide a detailed explanation of its determination to perform additional studies at the full generating facility capacity for an IC that has requested service below its full generating facility capacity.
Further information on the Option to Build – in 2009, FERC allowed MISO to directly assign to ICs 90% of the costs for network upgrades rated 345 kV and above (with the remaining 10% recovered on a system-wide basis) and 100% of the costs for network upgrades rated below 345 kV. In addition, the MISO OATT provided TPs two options for recovering network upgrade capital costs from ICs – 1) the IC would fund the network upgrades prior to construction, and the TP would not refund the non-reimbursable portion of this capital (the 90% or 100%) and would neither include the capital in its rate base nor charge the IC a return on this capital (as it is fully funded by the IC); and 2) the TP would fund the construction of the network upgrades (either initially or via reimburse IC after construction) and then recover the ICs portion over time through periodic network upgrade charges that include a return on the capital investment. The TPs had unilateral selection rights.
In June 2015, FERC initiated a complaint against MISO relating to these network upgrade funding options because FERC determined that allowing MISO TPs to unilaterally select transmission owner funding may be unjust, unreasonable, unduly discriminatory and may increase costs of interconnection service with no corresponding increase in service. In December 2015, FERC directed MISO to revise its tariff to remove the ability of a transmission owner unilaterally to elect to fund network upgrades. FERC found that such revision would not deprive MISO transmission owners of the opportunity to earn a return because, pursuant to the IC funding approach, the TPs make no investment on which they are entitled to a return.
After the TPs appealed the FERC decision to the D.C. Court of Appeals (D.C. Circuit), the DC Circuit vacated and remanded the decision, finding that FERC had not adequately responded to MISO TPs concerns that IC funding compels TPs to construct, own, and operate facilities without compensatory network upgrade charges, thus forcing them to accept additional risk without corresponding return as essentially non-profit managers of network upgrade facilities. The D.C. Circuit found that the MISO TPs would have to assume certain costs that are never compensated such as liability for insurance deductibles and litigation, including environmental and reliability claims. Moreover, the D.C. Circuit stated that the orders at issue suggest that FERC does not believe that the TPs are entitled to earn a return on capital for network upgrades funded by the ICs despite TP’s assumption of such costs. For these reasons, the D.C. Circuit stated that FERC must explain how investors could be expected to underwrite the prospect of potentially large non-profit appendages with no compensatory incremental return. FERC eventually restored in the MISO OATT the TPs unilateral right to determine the funding of the network upgrades.
The MISO TPs argued on rehearing in this generator interconnection reform proceeding that providing ICs the unilateral option to build interconnection facilities and stand-alone network upgrades was contrary to the regulatory compact and the D.C. Circuit decision. They asked for rehearing or, if denied, they requested that FERC clarify that TPs may fund construction costs incurred for the option to build facilities and then charge the IC a return, like the current provision in the MISO OATT. In other words, the TPs requested that their unilateral right to fund network upgrades be extended to the facilities for which the IC, under the reforms, now has a unilateral right to build. In Order 845-A, FERC denied the requests, stating that its reforms are not in conflict with D.C Circuit decision as the concerns identified in the D.C. Circuit decision pertain solely to unique features of MISO’s OATT. Specifically, the D.C. Circuit’s primary concern was with FERC’s requirement that there be mutual agreement between the TP and the IC before the TP can elect to fund the interconnection, which would mean that the IC could effectively prevent the TP from assessing a network upgrade charge and receiving a return on its investment. FERC said its current reforms do not deprive TPs of the ability to earn a return of, and on, network upgrades, including stand-alone network upgrades. On the contrary, Order No. 2003 (initially establishing the more limited option to build in effect prior to Order 845) established a mechanism that explicitly allows TPs to earn a return of, and on, the costs of network upgrades that they fund. The concerns the D.C. Circuit identified are present only in MISO because MISO’s interconnection pricing policy is a unique variation from Order No. 2003 under which MISO directly assigns 90% or 1004 of the network upgrade cost responsibility to ICs. FERC denied the requests because they are essentially requesting FERC to allow MISO to deviate from the requirements outlined in Order No. 845 based on MISO’s interconnection pricing policy, which is itself a deviation from Order No 2003. FERC stated that If MISO wishes to make such a request, it should do so when it submits its Order No. 845 and 845-A compliance filing, and FERC will consider it then.
FERC reiterated in this Order that it expanded the option to build for ICs as ICs have incentives greater than those of TPs to reduce network upgrade costs. FERC also found that concerns that the option to build will compromise system reliability are misplaced because they ignore the safeguards for reliability, including potential for NERC violations. already in place for the existing option to build. If the IC exercises its option to build, FERC provided for the TP’s recovery of costs of executing the responsibilities enumerated for TPs (project oversight, for example) and expects the TP and IC to negotiate this amount and clearly state it in the LGIA. Reporting under the reforms will begin in 2020.
FERC opened an investigation and ordered a hearing to determine if Southwest Gas Storage Co. may be substantially over-recovering its cost of service, resulting in unjust and unreasonable rates. FERC also found that twenty gas companies have complied with the filing requirements of Order No. 849 and terminated their FERC Form 501-G proceedings without any further action, finding their rates to be just and reasonable. In July 2018, FERC issued Order No. 849 which required each interstate natural gas pipeline to file a one-time report (Form No. 501-G) and provide a rough estimate of its return on equity before and after passage of the Tax Cuts & Jobs Act of 2017 and changes to the Commission’s income tax allowance policies in response to rulings by the D.C. Circuit.
The investigation and hearing on Southwest will determine whether the existing rates are just and reasonable in accordance with section 5 of the Natural Gas Act (NGA). The Commission has not yet determined a just and reasonable return on equity for Southwest Gas Storage, and therefore set this issue, among others, for hearing before FERC’s administrative law judges. FERC directed the company to file a cost and revenue study for the latest available 12-month period within 75 days of the issuance of its order.
The 20 companies whose FERC Form 501-G proceedings were terminated without further action (RP19-274-000 et al.) are: American Midstream (AlaTenn); Big Sandy Pipeline, LLC; Bison Pipeline LLC; Black Hills Shoshone Pipeline, LLC; Centra Pipelines Minnesota Inc.; Central Kentucky Transmission Company; Chandeleur Pipe Line, LLC; Discovery Gas Transmission LLC; Dominion Energy Questar Pipeline; Elba Express Company, L.L.C.; Fayetteville Express Pipeline LLC; Garden Banks Gas Pipeline, LLC; Gulf Shore Energy Partners, LP; Gulf States Transmission LLC; KPC Pipeline, LLC; Lake Charles LNG Company, LLC; MarkWest New Mexico, L.L.C.; PGPipeline LLC; Southern LNG Company, L.L.C.; and Western Gas Interstate Company.
Recently FERC has issued orders directing TOs to eliminate the two-step approach for addressing ADIT in formula rates with projections. Previously, many TOs believed that the IRS required, for projecting ADIT balances, use of its proration methodology and then, in addition, use of the conventional 13-month averaging to that proration result. TOs thought the averaging was necessary in order to meet the IRS’ consistency requirements. In April 2017, the IRS issued a Private Letter Ruling (PLR) in which it clarified that the averaging, in addition to the proration methodology, was unnecessary. Thus TOs have been making filings to eliminate the averaging from the ADIT projection.
For the True-up calculation, all TOs have held that the IRS proration requirement does not apply to the calculation of the revenue to which the utility would have been entitled had it based its projected rate computation on what turned out to be the actual results for that period. The result is to ignore proration in the True-up calculation and reverse the impact of the application of the proration requirement embedded in the projected rate calculation (i.e., the true-up would be to a revenue number that did not reflect any proration). However, in the PLR, the IRS said that to make proration matter, the freedom from proration can only apply to the variations in the changes in the ADIT balance used in the True-Up component, not to the entire change in the ADIT balances used in that computation. The IRS stated that the True-Up component is determined by reference to a purely historical period and, accordingly, there is no need to use the proration formula to calculate the differences between projected ADIT balance and the actual ADIT balance during the period. In calculating the True-Up, proration applies to the original projection amount, but the actual amount added to the ADIT over the test year is not modified by application of the proration formula.
ATC proposed to FERC in EL18-157 not to apply the proration formula to the variances in the monthly ADIT balances but, instead, to apply its “normal” regulatory convention (a 13-month average) to those variances. ATC proposed to add the result of this calculation to the ADIT balance originally used in the calculation of the projected rate – that is, the prorated balance. In this way, ATC would preserve the effect of the proration requirement embedded in the projected rate, avoid applying proration to the differences between projected and actual ADIT balances and comply with the consistency rule with respect to those variances.
GridLiance and Certain MISO TOs take a different and more complicated approach in the True-up calculation. The differences attributable to over-projection of ADIT in the annual projection will result in a proportionate reversal of the projected prorated ADIT activity to the extent of the over-projection. The differences attributable to under-projection of ADIT in the annual projection will result in an adjustment to the projected prorated ADIT activity by the difference between the projected monthly activity and the actual monthly activity. However, when projected monthly ADIT activity is an increase and actual monthly ADIT activity is a decrease, actual monthly ADIT activity will be used. Likewise, when projected monthly ADIT activity is a decrease and actual monthly ADIT activity is an increase, actual monthly ADIT activity will be used.
Please contact Dumais Consulting if you want to see examples of both approaches.
In ER19-303, FERC awarded Duquesne the Abandonment Incentive and CWIP in rate base for a PJM project named the Beaver Valley Deactivation Transmission Project. The Project is part of a suite of projects needed to address reliability violations resulting from FirstEnergy’s intent to deactivate about 4,000 MW of nuclear generation between May 31, 2020 and October 31, 2021 (four generation facilities are expected to be deactivated, including Davis-Besse Unit 1, Beaver Valley Unit 1, Beaver Valley Unit 2, and the Perry Unit). The Beaver Valley Units 1 and 2 are located within Duquesne’s service territory in southwestern Pennsylvania. The Project consists of constructing a new Elrama 135 kV substation, connecting seven 138 kV transmission lines to the new substation, reconductoring several transmission lines, establishing a new circuit, and constructing transmission tie lines from the new Elrama substation to a FirstEnergy substation. Duquesne estimates that the Project will cost $38.4 million and has a projected in-service date of June 1, 2021.
In ER19-297, FERC awarded Mid-Atlantic Interstate Transmission, LLC (MAIT) and West Penn Power Company (West Penn) the Abandonment Incentive for transmission upgrades, which comprise the Generator Deactivation Project, a PJM project needed to address reliability violations resulting from the same nuclear retirements described above. The Generator Deactivation Project is estimated to cost $144.4 million and will include three transformer replacements, construction of a new substation and transmission lines, and reconductoring of existing transmission lines and terminal equipment enhancements. The Generator Deactivation Project has a projected in-service date of June 1, 2021.
FERC also confirmed that both Duquesne and MAIT and West Penn are eligible to seek recovery of 50 percent of their portion of prudently-incurred abandonment costs, net of the closing out of the transaction and sale of associated assets, for both projects expended prior to the date of issuance of this order. However, such recovery, along with any recovery pursuant to the Abandonment Incentive, is subject to a future filing establishing the justness and reasonableness of including such costs in rates.
Duquesne did not propose accounting procedures to ensure that customers will not be charged for both capitalized AFUDC and corresponding amounts of CWIP proposed to be included in rate base and must do so on compliance.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.