On April 11, 2019, in FERC ER19-1553, Southern California Edison (SCE) filed changes to its transmission formula rate due to dramatic material changes to SCE’s regulatory and financial conditions that have occurred since SCE filed its currently effective Formula Rate (the “Second Formula Rate”) in October 2017. Beginning in December 2017, several wind-driven wildfires impacted portions of SCE’s service territory and caused substantial damage to both residential and business properties and service outages for some of SCE’s customers. California has unique inverse condemnation laws. These laws provide that an electric utility will be held strictly liable for property damages and legal fees if its facilities are the substantial cause of a fire regardless of fault and even if the utility was fully compliant with all applicable rules and regulations and acted reasonably. As a result of these laws and recent fires, SCE is exposed to significant potential wildfire damage claims. In 2017, the California Public Utilities Commission (“CPUC”) issued a decision holding that it could preclude a utility from recovering these court-assigned costs if it finds the utility was not prudent, even if the source of the alleged imprudent conduct was not directly the cause of the fire. The decision creates significant CPUC-related cost-recovery uncertainty and, as a result, SCE recently announced an accrual of a 2018 fourth quarter non-cash charge against earnings of $1.8 billion due to potential wildfire damages that would be dependent upon CPUC-approval.
SCE filed proposed revisions to its Formula Rate to account for the above risk in a manner sufficient to attract the capital necessary to provide safe and reliable electric service. SCE requested a base ROE that is founded on, and fully supported by, FERC’s established ROE policies. SCE applied the four financial models utilized in the Commission’s October 2018 Order Directing Briefs in the New England Transmission Owner (NETO) ROE cases - which includes the Discounted Cash Flow (“DCF”) model, the Capital Asset Pricing Model (“CAPM”), the historical Risk Premium model, and Expected Earnings—and determined the ROE that is required to reflect the significant non-wildfire regulatory and legislative risks that SCE faces as a public electric utility operating in California. That base ROE is 11.12%. SCE also analyzed how the additional risks it faces as a result of wildfires affect SCE’s ability to attract capital. While these wildfire risks required additional analysis to complement the conventional application of the four financial models, this additional analysis is fully consistent with FERC’s rationale in the NETO Order Directing Briefs because this analysis connects SCE’s circumstance and its unique risks with the capital attraction standard that underlies the Commission’s ROE policies. SCE accordingly requests an increase to its base ROE 0f 6.0% to account for the asymmetric wildfire risk (total base ROE of 17.12%). SCE also asks that, in determining its capitalization and costs of capital, the charge to earnings described above ($1.8 B) be removed from its common equity balance along with any debt incurred related to the wildfire liabilities. SCE’s proposed retail transmission revenue requirement for calendar year 2019 (effective June 12, 2019) is $1,328,294,741, which compares to the current amount for calendar year 2018 of $1,038,486,906.
On April 2, 2019 in Docket No. ER19-1515, First Energy, on behalf of on behalf of its affiliates American Transmission Systems, Incorporated (“ATSI”), Mid-Atlantic Interstate Transmission, LLC (“MAIT”) and the
West Penn Power Company (“West Penn”) requested the Abandonment Incentive for transmission upgrades required to resolve certain of the reliability violations as a result of generator deactivations (“Generator Deactivation Project”), if the Project is abandoned or cancelled, in whole or in part, for reasons beyond the control of the Applicants. Duquesne recently requested the Abandonment and CWIP incentives for its portion of the upgrades.
In August 2018, Bruce Mansfield 1, 2, and 3 (2,490 MW), Eastlake 6 (24 MW), Sammis Diesel (13 MW), Sammis 5, 6 and 7 (1,491 MW) notified PJM of their intent to deactivate on June 1, 2021 or June 1, 2022.
Following this initial announcement, Bruce Mansfield 1 and 2 then announced on November 7, 2018, an accelerated retirement date of February 5, 2019. Consequently, PJM determined that the system enhancements that comprise the Generator Deactivation Project are necessary to maintain reliability. PJM designated the First Energy affiliates, as PJM Transmission Owners, as the entities responsible for constructing the necessary upgrades because the upgrades are to be built in their respective service territories. The Generator Deactivation Project serves a single combined purpose of ensuring
reliability by resolving generator deliverability violations as a result of generator retirements. The Project includes transformer replacement, breaker construction and replacement, and extensive reconductoring, spanning three transmission owner zones with a total estimated cost of $91.7 million.
On March 29, Commonwealth Edison (ComEd) submitted proposed modifications to its transmission formula rate to clarify that ComEd may recover its portion of the cost to construct, operate, and maintain the Superconductor Cable Development Project (“the Project”) in the central business district of Chicago, Illinois. ComEd also requested the Abandonment Incentive for the Project. The Project is a Supplemental Project under the PJM Tariff, and thus its costs will be charged solely to transmission customers in the ComEd zone.
The Project employs high temperature superconductor technology that serves a transmission function even though it operates at a voltage (12kV) that ordinarily is characteristic of distribution facilities (the filing contains expert testimony on why this Project is a transmission facility under FERC’s seven-factor test). This will be the first such permanent 12kV high temperature superconductor addition in the United States that links substations to form a new looped transmission path. The Project is being built pursuant to the Resilient Electric Grid Program of the U.S. Department of Homeland Security (“DHS”). DHS and American Superconductor Corporation (“AMSC”) (the contractor who manufactures the high temperature superconductor material) will assume approximately 53% of the costs of the Project, leaving 47% – a projected $67 million – to be paid by ComEd. The Project will be in the very heart of the Chicago Central Business District, in an area served by three substations: Dearborn, Plymouth Court, and State. Two of the substations, Dearborn and Plymouth Court, are among the remaining radial substations in the area, served by 69kV underground cables. Only the third substation, State, is part of the looped transmission system. Due to their radial configuration, the Dearborn and Plymouth Court substations are not able to fully back-up the system in the event of a catastrophe. As planned, the proposed high temperature superconductor cable system would provide third contingency capability (“N-3”) to the substations included in the Project. This means that at a given substation, three of the transformers, or three of the supply lines, or a combination of these could be out of service and the remaining equipment could still supply the distribution load while staying within the applicable maximum equipment ratings, except at peak load, which would require outage of some load for only a matter of minutes. The Project is being developed in two phases. The installation in Phase 1 would be a high temperature superconductor cable located at the Northwest TSS 114 substation, in Chicago but a few miles north of the Chicago Central Business District. The purpose of Phase 1 is simply to learn and test the new technology, but it will connect two terminals of the substation, and by doing so will increase the design contingency of that substation to N-2. Once the Phase 1 installation is constructed, and after it has been in satisfactory operation for a year, installation will commence on Phase 2, the main portion of the Project in downtown Chicago. ComEd anticipates placing Phase 1 of the Project in service in the first quarter of 2021. Phase 2 would not begin until after a full year of operation of the Phase 1 installation, in order to evaluate any changes or considerations that should be factored into Phase 2. Current projections are that Phase 2 would come on line in the fourth quarter of 2026.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.