On September 16, 2019, in Docket ER18-169, Southern California Edison (SCE) filed a settlement that it offered to the intervenors that is intended to resolve all issues in this Docket as well as in EL18-44. Below are some of the key provisions:
On September 6, 2019, in Docket No. 19-2769, Exelon, on behalf of PEPCO, requested recovery of 50% of prudently-incurred costs associated with the PEPCO-assigned PJM baseline reliability projects (“Potomac River Project”) that PJM subsequently cancelled, under its Regional Transmission Expansion Plan (“RTEP”) Protocols. Exelon requested recovery over five years of $616,472.36 through PEPCO’s formula rate, which is 50% of the now-abandoned capital costs of the Potomac River Project. PEPCO did not have an abandonment incentive to recover 100% of the cancelled project costs. The rate impacts are minimal. Under the PJM RTEP obligation-to-build requirements, PEPCO commenced construction of the Potomac River Project. However, PJM cancelled the Potomac River Project, which was beyond PEPCO’s control. PEPCO incurred costs consistent with the timetables required for it to satisfy its OATT obligations and directives of PJM. The allocation of the costs of the Potomac River Project is governed by PJM’s OATT as it was in effect at the time that the Potomac River Project was approved, and Exelon is only seeking approval of the recovery of the costs, not the cost allocation, which is outside the scope of this proceeding.
On August 16, 2019, in Docket RM17-8, FERC issued an order on rehearing and clarification regarding generator interconnection reforms. In the Order, FERC affirmed that the DC Court of Appeals decision in Ameren, where the Court remanded to FERC a decision to remove from the MISO tariff the unilateral transmission owner funding of interconnections, did not implicate FERC’s revisions to the pro forma Large Generator Interconnection Agreement (LGIA) adopted in Order No. 845. Order 845 did not change the funding option pursuant to which transmission providers can earn a return of, and on, the costs of network upgrades. FERC also clarified that RTOs and ISOs can request an independent entity variation and address whether the relevant provisions in their tariffs implicate Ameren. Lastly, FERC addressed rehearing requests on the indemnity provision in the LGIA. FERC declined to expand the applicability of the indemnity provision because: (1) the existing language already provides indemnification for the transmission provider for a significant number of third party claims arising from the interconnection customer’s option to build construction; (2) even if the indemnity provisions do not apply, the transmission provider may pursue a claim for breach if the interconnection customer’s conduct . . . breaches the interconnection agreement; and (3) article 5.2 gives the transmission provider ‘significant oversight authority’ over the option to build, which, if exercised properly, gives the transmission provider a significant role in ensuring that the interconnection customer’s exercise of the option to build does not expose the transmission provider to liability. FERC denied a request that it clarify that transmission providers have the right to seek both indemnification and direct damages from the interconnection customer for the life of the facilities that the interconnection customer
constructed pursuant to the option to build since the pro forma LGIA already makes clear that indemnity provisions and a party’s right to seek direct damages for defaults under the pro forma LGIA survive the termination of the agreement. FERC also found that the term “construction” used in pro forma LGIA article 5.2(7) is not unreasonably vague, especially considering FERC’s intentional omission of the terms “engineering” and “procurement,” which FERC used in other LGIA articles (5.2(1) and 5.2(2)).
In ER14-2529, in a series of Commission orders, FERC granted PG&E’s requests for a 50-basis point return-on-equity (ROE) adder to its transmission rates (RTO-Participation Incentive) for its continuing membership in CAISO. In granting the request, FERC rejected the California Public Utilities Commission’s (CPUC) argument that PG&E was not eligible for the incentive because California law required PG&E to participate in CAISO. On appeal, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) remanded the underlying orders and instructed FERC to “inquire into PG&E’s specific circumstances, i.e., whether it could unilaterally leave [CAISO] and thus whether an incentive adder could induce it to remain in [CAISO].” On August 20, 2018, the Commission issued an initial order on remand establishing briefing procedures regarding those issues. Having reviewed the record, including the additional briefing provided by parties to this proceeding, FERC found that California law does not mandate PG&E’s participation in CAISO, and that the RTO-Participation Incentive induces PG&E to continue its membership. FERC therefore reaffirmed its prior grant of PG&E’s request for the RTO-Participation Incentive.
Commissioner Glick consented with a separate statement. In his statement, Commissioner Glick states that this PG&E case reinforces the importance of taking a hard look at the RTO-Participation Incentive in the Commission’s ongoing incentive proceeding (PL19-3). He went on to state that FERC’s current approach to incentivizing RTO participation hands transmission owners across the country hundreds of millions of dollars every year with little indication that any of that money makes a meaningful difference in their decisions to enter or remain in an RTO, and FERC must carefully review whether the RTO-Participation Incentive remains money well spent and is consistent with FERC’s obligation under the FPA to ensure that transmission rates are just and reasonable.
On June 27, 2019 in ER19-2272, Xcel Energy Services, on behalf of its affiliate Public Service Company of Colorado (PSCo), requested the inclusion of a regulatory asset tariff provisions for the early retirements of Comanche Unit 1 and Comanche Unit 2 in the production formula rate template (Formula Rate) used to derive wholesale rates under the PSCo Assured Power and Energy Requirements Service Tariff (Tariff). Xcel requests FERC accept the Formula Rate revisions providing for the creation of the regulatory assets for Comanche Unit 1 and Comanche Unit 2 and the seven-year amortization period for the rate recovery starting at the retirement dates for Comanche Unit 1 and Comanche Unit 2, effective September 1, 2018.
Comanche Unit 1 and Comanche Unit 2 are steam production (electric generation) units whose costs are presently recovered in the Production Formula. Comanche 1 is a coal-fired generating unit located near Pueblo, Colorado, with a capacity of 325 MW which had a scheduled retirement date of 2033. Comanche 2 is a coal-fired generating unit located on the same site with a capacity of 335 MW and had a scheduled retirement date of 2035. The two units are currently used to serve both retail native load customers in Colorado and wholesale requirements service customers under the Tariff. The request is supported by the approval by the Colorado Public Utilities Commission (“CoPUC”) of the early retirement of Comanche Unit 1 and Comanche Unit 2 in its Decision No. C18-0761 in Proceeding No. 16A-0396E, issued on September 10, 2018. In addition, in Decision No. C18-0762 in Proceeding No. 17A-0797E, which was issued contemporaneously with Decision No. C18-0761, the CoPUC approved creation of a regulatory asset to collect the incremental, accelerated depreciation costs associated with the early retirements.
The requested regulatory assets will reflect the differences between depreciation expense at the currently effective depreciation rates and the depreciation expense at accelerated depreciation rates required by Generally Accepted Accounting Principles due to the earlier retirement. The regulatory asset for Comanche Unit 2 also includes any common assets that will be retired when Unit 1 and 2 are retired. The regulatory assets are estimated to be accumulated to $125.3 million for Comanche Unit 1 on December 31, 2022 (date of retirement), and $101.1 million for Comanche Unit 2 on December 31, 2025 (date of retirement). The portion of the regulatory asset costs associated with wholesale requirements services (approximately 8 percent) would be amortized over seven years beginning the first rate year after retirement: January 1, 2023 for the regulatory asset for Comanche Unit 1, and January 1, 2026 for the regulatory asset for Comanche Unit 2.
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.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.