In early June 2019, in Docket ER19-2029, LSP Transmission Holdings II, LLC, Cardinal Point Electric, LLC, and LS Power Midcontinent, LLC (collectively, “LS Power”) submitted a complaint to FERC against the MISO, seeking to remedy flaws in MISO’s economic planning process. Although economic enhancements below 345 kV can have regional benefits, they are excluded from the Market Efficiency Project Category, a competitive process, because Market Efficiency Projects must have a voltage level of at least 345 kV and have projects costs more than $5 million. If economically beneficial projects below 345 kV are identified and move forward, they are categorized as “Other Projects”, which are not subject to a competitive process.
MISO is responsible for planning all networked transmission facilities above 100 kV, and MISO plans to meet regional reliability, economic, and public policy needs. Currently, MISO has two categories of projects eligible for regional cost allocation – Market Efficiency Projects and Multi-Value Projects. Economic projects below 345 kV or that cost less than $5 million that do not also resolve a reliability issue fit neither category. Instead, to the extent that these economic enhancements below 345 kV move forward, they are considered “Other Projects,” not subject to a competitive process. Additionally, the costs of Other Projects are allocated solely to the transmission owner zone where the project is located regardless of the beneficiaries. The current voltage threshold for Market Efficiency Projects effectively grants incumbent TOs in MISO a federal right of first refusal to build regionally economic enhancements that do not meet the Market Efficiency Project thresholds. A proposal from MISO that is pending before FERC does not remedy this issue, even though it lowers the threshold to 230 kV. Under that MISO proposal, economic enhancements below 230 kV, shown to have regional benefits, nevertheless would be allocated to a single zone, thus ensuring the projects are not eligible for competition. LSP Power says in its filing that “[i]t is time for the Commission to send a clear message that it will not allow such end runs around Order No. 1000.”
To remedy this issue, the Commission should require MISO to utilize its existing criteria and procedures for Market Efficiency Projects by lowering the voltage threshold for Market Efficiency Projects down to 100 kV. This would expand the portfolio of Market Efficiency Projects that are subject to competition. Currently the only reason to exclude projects with voltages below 345 kV from the Market Efficiency Project category is that the cost allocation methodology for Market Efficiency Projects allocates 20% of the costs of the project to the entire region. FERC can require MISO to propose a separate cost allocation method for regionally beneficial economic projects below 345 kV, with such method reflecting the fact that multiple Transmission Pricing Zones can benefit from the project.
In Docket No. ER19-103, Wisconsin Electric Company (WEC) sought approval: (1) to amend its Formula Rate Wholesale Sales Tariff (Generation Formula Rate) to include amounts recorded in Account 182.2 (Unrecovered Plant and Regulatory Study Costs) as an adjustment to rate base; and (2) to recover in the Generation Formula Rate a return of and on the unamortized balance that is transferred to Account 182.2 and amortized to Account 407. WEC claims that its request is consistent with FERC precedent that allows utilities to recover 100% of the return of and on prudently incurred unamortized investment remaining when a generating plant is retired after many years in service. WEC refers to the treatment provided the retired Yankee Atomic Nuclear Plant in New England.
WEC recently retired Pleasant Prairie, a two-unit, coal-fired generating facility located in the Pleasant Prairie, Wisconsin, with a capacity of 1190 MW (595 for each unit). Pleasant Prairie’s Unit 1 entered service in 1980, and Unit 2 entered service in 1985. Pleasant Prairie has served WEC’s customers for nearly 38 years and has produced approximately 250 million MWh of power for WEC’s customers during those years. Pleasant Prairie has provided reliable service at reasonable cost and has performed well when compared to its counterparts in the WEC generation fleet and to similarly sized coalfired generating facilities. For most of its service life, Pleasant Prairie was an economically desirable Plant. Beginning around 2008, however, several factors outside of WEC’s control began to diminish the value of having Pleasant Prairie. These factors include a significant loss of WEC’s industrial load due to both the recession in 2007-08 and improvements in energy efficiency; declining energy prices in MISO due to declining costs of alternative sources of generation, particularly natural gas and renewable alternatives; and a corresponding reduction in the dispatch of the plant in MISO markets. Subsequently, after WEC determined that its customers would benefit substantially from Pleasant Prairie’s retirement, WEC requested approval from MISO under Attachment Y to retire Pleasant Prairie. MISO approved the Attachment Y request, finding no reliability impediments to retirement. Pleasant Prairie was then retired in April 2018. At the time of its retirement, Pleasant Prairie had an unamortized plant balance of approximately $665 million.
Background: In late 2015, FERC initiated a Section 206 investigation of the New England transmission formula rate. FERC found that the existing formula rate lacked transparency, may not be treating certain cost components correctly, and may not synchronize local and regional revenue requirements such that overcollections could be occurring. After over two and one-half years of settlement negotiations with the six New England state regulators and municipal customers in Massachusetts, along with FERC trial staff, the New England Transmission Owners (“NETOs”) filed a settlement in August 2018. The Settlement is supported by the consumer advocates for Massachusetts, Connecticut and Maine as well as NESCOE. The consumer advocates and the states had technical experts and experienced counsel to assist them in the negotiations. ISO-NE stakeholders approved the Settlement by a vote of 96% in favor. The Massachusetts municipal customers and FERC trial staff filed comments opposing the settlement.
FERC may approve contested settlements under the following conditions, based upon the Trailblazer case: (1) the Commission may make a decision on the merits of each contested issue; (2) the Commission determines that the settlement provides an overall just and reasonable result; (3) the Commission determines that the benefits of the settlement outweigh the nature of the objections, and the contesting parties’ interests are too attenuated; and (4) the Commission determines that the contesting parties can be severed longstanding principle that it is the “end result” of the rate setting process that counts, not each individual component of the rate.
FERC Order dated May 22, 2019: In this Order, FERC rejected the settlement and remanded the case back to the Chief ALJ for hearing procedures to resume. FERC determined that it was unable to approve the settlement using the Trailblazer precedent. As for item 1, FERC found that the record is inadequate to weigh each issue individually. For example, the proposed formula rate templates include numerous references to an “Attachment,” but the attachments have not been provided for review; the allocators are not verifiable or transparent; and the formula rate templates include numerous external references, which are not clearly defined. As another example, the proposed formula rate templates alternate between using five-quarter average balances and beginning-of-year and end-of year average balances to calculate rate base items without explanation. As for item 2, FERC could not determine whether the overall settlement package falls within a just and reasonable range, because the record lacks crucial information, such as the method or derivation of the allocation factors, information to determine whether several components of the rates are discretionary and in excess of the cost of providing transmission service, preventative controls for double recovery of certain components of the rates, and how the rates exclude non-transmission amounts from the rates. Moreover, Contesting Municipals have provided evidence suggesting that the Settlement will leave them worse off than if the issues were litigated as they provide detailed calculations, testimony, and workpapers indicating that the Settlement’s proposal to retain existing service company allocations results in an increase in the transmission revenue requirement of $42.5 million over the transmission revenue requirement that would result if the Settlement used allocations that are known and measurable. As for item 3, FERC found that the record was insufficient to determine whether the Settlement’s benefits outweigh the objections to it; in fact, Contesting Municipals present evidence that there is more harm than benefit. For item 4, FERC determined that the issues raised by the Contesting Municipals were not severable because they raise valid concerns involving the overall costs of transmission service under the Tariff that apply to all parties. For these reasons and based on the overall lack of necessary detail and transparency throughout the Settlement, FERC was unable to approve the Settlement and remanded this proceeding to the Chief Administrative Law Judge to resume hearing procedures.
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.
On May 14, 2019, FERC found that the Pequonnock Project has received construction approval from an appropriate state siting authority that considered whether the project ensured reliability or reduced congestion and therefore the Project is entitled to the rebuttable presumption established in Order No. 679 and satisfies the section 219 requirement that a project ensure reliability or reduce the cost of delivered power by reducing transmission congestion. As a result, FERC granted the risk reducing incentives (Abandoned Plant and CWIP incentives) but denied the request for a 50-basis point ROE Incentive Adder. As for the ROE Incentive Adder, FERC found that United Illuminating failed to make the first demonstration set forth in the 2012 Policy Statement in that it has not shown that the Pequonnock Project 1) will relieve chronic or severe grid congestion that has had demonstrated cost impacts to consumers; (2) will unlock location constrained generation resources that previously had limited or no access to the wholesale electricity markets; or (3) will apply new technologies to facilitate more efficient and reliable usage and operation of existing or new facilities. United Illuminating has not shown that its use of smart grid technology or “hardened resilient design” reflects the application of new technologies to facilitate more efficient and reliable usage and operation of existing or new facilities. Lastly, United Illuminating also has not demonstrated that the Pequonnock Project otherwise faces risks and challenges either not already accounted for in United Illuminating’s base ROE or addressed through risk-reducing incentives.
Alternative Transmission, a provider of transmission services without using wires, Requests FERC Find that it is a transmission provider subject to its regulations
On April 17, 2019 in Docket No. EL19-69, Alternative Transmission Inc. (ATI) requested that FERC issue an order confirming that (1) the alternative transmission facilities and services described in its petition provide “transmission of electric energy in interstate commerce” subject to FERC’s jurisdiction under Parts II and III of the Federal Power Act (FPA) and (2) ATI as the owner or operator of the described facilities will be a “public utility” under Parts II and III of the FPA. ATI plans to transmit electricity across state lines without the use of wires. It proposes to do so by constructing electric energy transfer stations—charging and discharging—at locations in the continental United States. At the charging stations, electric energy generated by unaffiliated entities will be transferred to a mobile medium--e.g., a shippable container of an electrically chargeable, dischargeable, and rechargeable medium. The charged mobile medium then will be transported across state lines by rail (and possibly tractor-trailer, boat or airplane, or any combination of these) to discharging stations at different locations. At the discharging station, the medium in the containers will be available for instantaneous dispatch as instructed, until the charge is depleted and the medium becomes available for recharge. ATI will deliver electric energy into areas accessible by surface transportation (and possibly water or air) where (1) current or forecast demand for delivered electric energy cannot adequately be met by existing wire transmission corridors, or (2) the ATI’s approach is the most timely or most economical solution for meeting existing or forecast demand. Further applications are conceivable, such as diverting natural gas directly to combustion turbines or combined-cycle generating units constructed at or proximate to the production of those natural gas reserves and generating electricity to charge the media in container cars for transport to markets using neither pipelines nor wires. Additionally, ATI’s proposal could address widespread power outages from emergencies or disasters or from cyber-attacks or improper maintenance. Discharging stations can be modular and transported where needed.
There is more information in the ATI filing, including an affidavit further explaining the ATI approach, which can be found at https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14767433.
In early May, in Docket No. EL19-70, a group of generators in PJM requested a declaratory order from FERC on several reactive power issues for which there is uncertainty in the FERC methodology. The generators requested that FERC find the following as to reactive power revenue requirement calculations:
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.
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.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.