​FERC denied a formal challenge to the Westar full requirements service formula rate (FR) in a March 21, 2019 decision in ER19-17.  The Westar FR is based upon historical amounts.  As such, Westar continued to use the 35% federal income tax rate in its June 2018 FR update, which was based upon 2017 data.  The Kansas Electric Coop challenged Westar, claiming that Westar should have used the 21% federal tax rate in its June 2018 update and additionally adjusted the revenue requirement to a 21% federal tax rate for the period January 2018 through May 2018.
 
FERC disagreed with Kansas as the Westar FR uses a historical test year without a true-up based on actual costs.  Accordingly, Westar correctly applied a 35 percent federal corporate income tax rate in the calculation for the period from January 1, 2018 through May 31, 2018, and for the period from June 1, 2018 through May 31, 2019.  The 2018 Annual Update was properly based on 2017 costs, including the 35 percent federal corporate income tax rate in effect in 2017; the reduction in the federal corporate income tax rate did not take effect until January 1, 2018.  In a prior Duke Energy Progress case, FERC stated that it generally requires that formula rate inputs be calculated on a synchronized basis over the same test period, such that the use of a historical formula rate methodology generally dictates the use of the federal corporate income tax rate in effect during the historical test year period, absent a contrary statement in the filed rate.  

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.