On March 15, 2019, in Docket No. ER19-1359, the United Illuminating Company (UI), an affiliate of Avangrid, requested rate incentives for a substation replacement project. UI’s Pequonnock Substation Project will replace the existing Pequonnock substation and will include (1) a new 115-kV/13.8-kV gas insulated substation; (2) the relocation and installation of five existing 115-kV overhead transmission lines; and (3) the relocation and installation of two 115-kV underground high-pressure gas filled cables and one underground XLPE cable, each ranging in length from about 500 feet to 730 feet. The Pequonnock Substation Project is approximately a $101.6 million electric transmission investment and is expected to be placed in service on or before December 1, 2022. It will deploy smart grid communications-enabled technology and a resilient hardened substation design to improve the reliability of ISO-NE’s bulk electric system and to protect and maintain the transfer of uninterrupted power flow along the coast of southwestern Connecticut bordering Bridgeport Harbor.
UI requested (1) 100 percent recovery of prudently incurred costs in the event the Pequonnock Substation Project is abandoned, in whole or in part, for reasons outside of UI’s reasonable control (“Abandoned Plant Incentive”); (2) inclusion of 100 percent Construction Work in Progress in rate base (“CWIP Incentive”); and (3) a 50 basis point return on common equity (“ROE”) incentive adder (“ROE
Incentive Adder”) for increased risks and challenges prompted by UI’s deployment of advanced technology and construction and operation of a substation that includes a resilient design. The Project is significant for UI as it represents over 12% of UIs existing transmission investment base.
In January 2019, parties filed briefs in these four ROE cases. There is a summary of these briefs at https://www.dumaisconsulting.com/blog/category/electric-transmission-roe. Below is a summary of the reply briefs. The next step in this paper hearing process for all four of these ROE cases is a FERC decision.
The bottom-line in the NETO’s reply brief is that FERC should disregard the recommendations of Complainants and FERC Trial Staff because the end-result of all of the ROEs proposed are too low to meet the requirements of Hope and Bluefield, where a ROE must be “commensurate with returns on investments in other enterprises having corresponding risks. . . . [and] sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and attract capital.” In Opinion No. 531, FERC found that a DCF midpoint of 9.39% failed to satisfy the Hope and Bluefield standards. Similarly, in Opinion No. 551, FERC found that a base ROE for the MISO transmission owners at the 9.29% midpoint of the DCF range would fail to meet these standards. The base ROEs recommended by the CAPs range from 8.91% for Complaint I to 8.33% for Complaint IV. The base ROEs recommended by EMCOS range from 8.70% for Complaint I to a shockingly low 7.67% for Complaint IV. FERC Trial Staff recommends base ROEs from as high as 9.41% for Complaint III to as low as 8.82% for Complaint IV. The fact that capital market conditions during the record periods underlying Complaints II, III, and IV remained comparable to the conditions that the Commission took into consideration in Opinion No. 531 along with FERC’s incontrovertible findings in Opinion Nos. 531 and 551 demonstrate that the ROEs proposed by the Complainants and Trial Staff fail the standards of Hope and Bluefield.
The Complainants and Trial Staff continue to advocate that the Expected Earnings approach to ROE should not be used as it does not measure the market cost of equity as it uses accounting data. Eliminating the Expected Earnings approach would lower the base ROE and ROE Cap. They also state that the CAPM and Risk Premium ROE methodologies are not precluded from critique as the way FERC proposed to use them in their October 2018 Order makes them more significant than how they were used to corroborate the ROE result in Opinion 531. Eastern Massachusetts Consumer-Owned entities (EMCOs) continues to state that the DCF remains a sound and reliable method to determine the market cost of equity. However, EMCOS recognize the FERC’s flexibility to incorporate other methodologies so long as those methodologies similarly seek to estimate the market cost of equity capital and are applied consistent with the economic theory and academic literature which underlie them. EMCOS’ identify concrete modifications, supported by significant evidence, which would create a methodology capable of fairly and accurately identifying a return that appropriately balances the needs of the NETOs’ investors against FERC’s obligation to protect customers from excessive rates. The Complainants and Trial Staff do not agree with the NETOs’ CAPM and Risk Premium results. As to the ROE Cap, EMCOS and CAPs both explain that FERC’s proposal that a broader zone – bounded at the top by the average of the three highest values produced by a DCF analysis, a CAPM analysis and an Expected Earnings analysis – should operate as the limit on total ROE is contrary to Order 679 on incentives as the rulemaking on Order 679 determined that the total ROE is limited by the top end of a DCF determined zone of reasonableness. CAPS state that the record supports a base ROE well below 10% for each of the four ROE periods. Complainants and Trial Staff all argue that there should be a high-end cut-off and a lower low-end cut-off than that proposed by the NETOs.
Duquesne Light Company requested from FERC authorization to use certain incentive rate treatments related to its investments in the Dravosburg-Elrama Expansion Project (the “Project”). The Project is part of a larger set of transmission upgrades that have been determined under the transmission planning process of PJM to be necessary to mitigate reliability criteria violations expected to result from the planned deactivation of two coal generation facilities in western Pennsylvania and eastern Ohio. Specifically, Duquesne Light seeks authorization to (1) include 100 percent of construction work in progress (“CWIP”) for the Project in rate base under its formula rate and (2) preauthorization to recover 100 percent of prudently incurred costs of the Project if it is abandoned or canceled, in whole or in part, for reasons beyond the control of the Company.
As a result of the planned deactivation of these two generating units, PJM identified approximately 145 reliability criteria violations across its footprint. The Project is part of $122 million of transmission upgrades that PJM determined are required to address the reliability criteria violations expected to result from these deactivations. Duquesne Light was designated by PJM as having the responsibility to construct and operate a portion of these upgrades which support the mitigation of approximately 20 of the reliability criteria violations. The Project has an estimated cost of $30 million and consists of new tie breakers, reconductoring four transmission lines, and expanding a planned 138 kV substation.
Duquesne supported its request for CWIP in rate base by explaining that its typical annual capital investment for transmission upgrades is $45 M and the Project will add significantly to its transmission capital investments. In addition, Duquesne supports its CWIP in rate base request as necessary to enhance cash flow in order to avoid downward pressure on the rating agency’s credit metrics. CWIP in rate base will also result in lower project costs and will avoid any rate shock when the project goes into service. To supports its request for the Abandonment Incentive, Duquesne states that it has no control over whether the generation resources with planned deactivations will deactivate as planned, or whether they will not, in which case PJM may need to cancel the Project as a result. Duquesne also states that the Project is subject to various state and local regulatory approvals, including transmission sitting and local permitting ordinances, which process can be both expensive and time-consuming and heavily contested. Multiple routing options must be studied and presented to the state commission to ensure that the most feasible and least impactful alternatives are pursued based on public input, land use, and environmental resources. Additionally, the Project is also subject to additional and unusual risk because Duquesne must coordinate closely with FirstEnergy as FirstEnergy’s transmission affiliates ATSI, Penelec, and West Penn have been designated with substantial construction responsibility for the remainder of the baseline projects necessary to mitigate the reliability criteria violations. This need for coordination creates substantial execution risk for Duquesne Light as changes to the nature and scope of the transmission upgrades to be constructed by First Energy’s affiliates could impact Duquesne’s construction of the Project.
On March 5, 2019, in Docket No. ER19-775, FERC granted NextEra Energy Transmission Midwest, LLC (NEET Midwest) request for incentive rate treatment pursuant to Order No. 679. NEET Midwest requests authorization to recover 100 percent of all prudently-incurred costs associated with its investment in the Hartburg-Sabine Junction 500 kV Competitive Transmission Project (Project) if the Project is abandoned or cancelled for reasons beyond NEET Midwest’s control (Abandoned Plant Incentive). The Project was identified through the 2017 MISO Transmission Expansion Plan (MTEP) as a Market Efficiency Project aimed at relieving both near-term and long-term system congestion in East Texas. The Project consists of five new high-voltage transmissions lines and one new substation. The 2017 MTEP Report concluded that the Project would provide estimated benefits in excess of 1.35 times the cost, have an estimated 20-year present value benefit of $214 million, and fully relieve congestion in the Sabine/Port Arthur area. MISO estimated that the Project would cost $129.6 million with an in-service date of June 1, 2023. As part of the selected project, NEET Midwest committed to forego allowance for funds used during construction and construction work in progress. In addition, NEET Midwest committed to a total project cost cap of $114.8 million; a cap on project operation and maintenance and the project revenue requirement during the first ten years of commercial operations; an ROE cap, including all Commission-approved incentives, of 9.8 percent, subject to reductions of up to 30 basis points for schedule delays; and a restriction on the capital structure to limit the equity share to 45 percent.
FERC granted NEET Midwest’s request for the Abandoned Plant Incentive as, in Order No. 679, FERC found that the abandoned plant incentive is an effective means of encouraging transmission development by reducing the risk of non-recovery of costs in the event a project is abandoned for reasons outside the control of management. FERC agreed with NEET Midwest that the Project faces significant regulatory, environmental, and siting risks that are beyond NEET Midwest’s control and that could lead to abandonment of the Project. FERC found that the total package of incentives, including the previously-granted incentives, as modified as part of the selected proposal, is reasonable, because it addresses the risks and challenges associating with the development of the Project. FERC made the Abandoned Plant Incentive for the Project available to NEET Midwest for 100 percent of prudently-incurred costs expended on and after March 5, 2019, the date of the order.
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.
In an Order issued by FERC on January 29, 2019 in ER18-2342, FERC accepted GridLiance Heartland’s proposed formula rate and protocols, including the MISO 10.32% base ROE, a 50 basis point RTO Participation Adder, and the Regulatory Asset and Hypothetical Capital Structure incentives, and granted GridLiance Heartland’s request for authorization to replicate its Formula Rate and incentives granted in this docket for future affiliates formed to operate in MISO. Prior to GridLiance using the formula rate (currently it does not own any transmission assets in MISO), it must submit a filing pursuant to section 205 to include the Formula Rate in the MISO OATT. FERC allowed GridLiance to include an income tax allowance in the proposed Formula Rate, but suspended the issue, subject to refund, and set the matter for hearing and settlement judge procedures. In fact, FERC initiated a Section 206 investigation (EL19-29) on the appropriateness of GridLiance’ s inclusion of an income tax allowance in two other formula rates - GridLiance High Plains and GridLiance West. FERC is concerned that including an income tax allowance in these Formula Rates may cause the same double recovery of income taxes described in United Airlines (DC Court of Appeals) and in FERC’s Revised Policy Statement on income taxes.
Below are items discussed by FERC in the Order that are worthy of individual summary:
1. FERC stated concern over the cost of debt included in the Formula Rate during the period when GridLiance Heartland may acquire construction financing but prior to acquiring any long-term debt. FERC found GridLiance Heartland’s proposal to use a proxy debt rate for the period in which GridLiance Heartland does not hold any debt just and reasonable, but also found that GridLiance Heartland’s Formula Rate should track actual costs to the extent possible. Accordingly, FERC required that GridLiance Heartland revise its Formula Rate to provide for recovery of actual short-term debt from construction financing, as necessary, during the period that GridLiance Heartland acquires construction financing but prior to issuing long-term debt.
2. FERC found GridLiance Heartland’s affiliate cost allocation description acceptable for informational purposes with the understanding that GridLiance Heartland must provide in its annual update and informational filings details describing the affiliate cost allocation used for the applicable rate year and any changes from the previous year, as well as the magnitude of such costs, and that any interested party will have the chance to review the affiliate cost allocation methodology and associated costs during the information exchange and challenge periods. GridLiance Heartland will bear the burden of proof to demonstrate that its affiliate cost allocation methodology and associated costs are just and reasonable.
3. FERC granted GridLiance Heartland’s request for authorization to use a hypothetical capital structure of 60% equity and 40% debt, as well as GridLiance Heartland’s proposal to adopt its actual capital structure, capped at 60% equity, once it has any assets in service. FERC understands that nonincumbent transmission developers have a particular need for the Hypothetical Capital Structure Incentive because it establishes certain financial principles that incumbent transmission owners currently have in place but that remain undetermined for nonincumbent transmission developers and that granting this request furthers the policy goal of facilitating the participation of nonincumbent transmission developers in the Order No. 1000 transmission planning processes, thereby encouraging competition.
4. FERC granted GridLiance Heartland the Regulatory Asset Incentive as nonincumbent transmission developers bidding on regional transmission projects in MISO’s competitive solicitation process must incur early pre-commercial and formation costs, but do not have a mechanism to recover these costs as they are incurred, as do incumbent transmission owners. FERC granted carrying costs, provided they would not result in a higher amount of interest than is allowed for construction expenditures that accrue in Allowance for Funds Used During Construction. FERC stated that GridLiance Heartland must make a section 205 filing to demonstrate that the pre-commercial and formation costs are just and reasonable before it includes them in rates and that GridLiance Heartland must establish that the costs included in the regulatory asset are costs that otherwise would have been chargeable to expense in the period incurred but were deferred consistent with the authorization granted herein.
 In the Policy Statement, FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) natural gas pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. FERC stated in the Policy Statement that it would address this issue for non-MLP partnership forms as those issues arise in subsequent proceedings. That is what they are doing here with GridLiance.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.