On August 9, 2019, in Docket No. ER19-2568, Pacific Gas and Electric Company (PG&E) filed a request to recover, through its formula rate, 50 percent of the prudently-incurred costs that it incurred associated with the development of its Diablo Canyon Voltage Support Project (DCVS Project) and its Atlantic – Placer 115kV Transmission Line Project (Placer Project), which were ultimately abandoned. On October 10, 2019, FERC found that PG&E has demonstrated that it qualifies to recover 50 percent of the prudently-incurred project costs for the DCVS Project ($1.1 M) and the Placer Project ($0.3 M) based on the facts and circumstances presented in this proceeding, consistent with Opinion No. 295. Specifically, FERC found that the transmission projects for which PG&E seeks abandonment cost recovery were cancelled based upon CAISO’s determination that the projects were no longer necessary. Thus, we conclude that the abandonment of the two projects was beyond PG&E’s control and that the costs incurred appear to be prudent and have not been shown to be unjust and unreasonable. Protesters objected to PG&E’s proposed 40-year amortization period. In its reply comments, PG&E agreed to change the amortization period to one year. FERC authorized a one-year amortization period, which will reduce potential overall costs by avoiding years of carrying costs and, accordingly, will reduce the impact on PG&E’s overall revenue requirement. FERC explained that the RTO/ISO participation adder does not apply to abandoned transmission projects, which are not turned over to the operational control of an RTO/ISO.
On May 31, 2019, in ER19-2023, Tucson Electric filed, pursuant to sections 205 and 219 of the Federal Power Act (FPA) and part 35 of the Commission’s regulations, a request to recover in rates 100 percent of the prudently-incurred costs that it incurred associated with the development of a 345 kV transmission line between Sahuarita and Nogales, Arizona (Nogales Project), which was ultimately abandoned. Tucson Electric states that, at a minimum, it is eligible to recover 50 percent of the prudently incurred costs associated with the Nogales Project. In its Order dated September 19, 2019, FERC denied Tucson Electric’s request for 100 percent recovery of prudently incurred costs associated with the Nogales Project and granted Tucson Electric’s request for 50 percent recovery, consistent with Opinion 295. FERC accepted and suspended the filing for a nominal period, effective August 1, 2019, subject to refund, and set for hearing and settlement judge procedures the types and level of prudently incurred costs and the appropriate amortization period. FERC denied Tucson Electric request for 100 percent abandoned plant cost recovery on a retroactive basis and many years after it incurred the costs (mostly prior to 2005) and abandoned the project (2014). Tucson Electric developed the Nogales Project (and incurred the associated costs) not only prior to its submittal of the Abandonment Incentive application, but also largely prior to the enactment of section 219 of the FPA and the issuance of Order No. 679.
On October 1, 2018, in EL17-45, the California Public Utilities Commission, the Northern California Power Agency (NCPA), the City and County of San Francisco, the State Water Contractors, and the Transmission Agency of Northern California (collectively, Complainants) filed a request for rehearing of the Commission’s August 31, 2018 order denying the Complaint filed in this proceeding against PG&E on February 2, 2017. The Complaint alleged that PG&E is in violation of its obligation under Order No. 890 to conduct an open, coordinated, and transparent transmission planning process because more than 80 percent of PG&E’s transmission planning is done on an internal basis without opportunity for stakeholder input or review. In the Order on Complaint, the Commission found that the Complainants had not shown that PG&E’s transmission owner tariff is unjust, unreasonable, unduly discriminatory, or unduly preferential because it does not require the asset management projects and activities in question to go through an Order No. 890-compliant transmission planning process (Order on Complaint, 164 FERC ¶ 61,161 at P 65). On September 19, 2019, FERC denied rehearing because the Complainants did not show that PG&E’s asset management projects and activities fall within the scope of Order No. 890’s transmission planning reforms or that failing to include these projects and activities within the Order No. 890 transmission planning reforms results in undue discrimination, violates EPAct 2005 requirements, or is inconsistent with Commission precedent.
FERC denied the Complaint in its initial Order on Complaint, finding that the Order No. 890 transmission planning reforms were intended to address concerns regarding undue discrimination in grid expansion, and to the extent that PG&E asset management projects do not expand the grid, they do not fall within the scope of those reforms. FERC found that the transmission-related maintenance and compliance projects, which it referred to as “asset management projects,” at issue in this proceeding do not, as a general matter, expand the CAISO grid. Instead, asset management projects include maintenance, repair, and replacement work, as well as infrastructure security, system reliability, and automation projects that PG&E undertakes to maintain its existing electric transmission system and to meet regulatory compliance requirements. However, the Commission acknowledged that to the extent that an asset management project will result in a non-incidental, or incremental, increase in transmission capacity, the incremental portion of the asset management project would be subject to the transmission planning requirements of Order No. 890 and would have to be submitted for consideration in CAISO’s TPP. FERC also noted that while the projects and activities at issue in this proceeding are not subject to the transmission planning requirements of Order No. 890, Complainants, other stakeholders, and PG&E are all likely to benefit from increased transparency into asset management projects. FERC strongly encouraged PG&E to continue its efforts to work with Complainants and other stakeholders to develop a process to share and review information with interested parties regarding asset management projects that are not considered through the TPP.
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.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.