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.
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.
In March 2018, FERC issued a Revised Policy Statement and Opinion No. 511-C, the remand order pursuant to United Airlines (a DC Court of Appeals decision addressing income taxes for master limited partnerships (MLP)). These FERC decisions explained that United Airlines’ income tax double-recovery concern precludes an MLP pipeline from claiming an income tax allowance in its cost of service based upon two findings:
On February 21, 2019, FERC issued an Order (Docket No. RP18-922) preliminarily finding that Trailblazer Pipeline’s rates should not include an income tax allowance on that part of investor supplied capital that is from certain Private Owners as the Private Owners incur only one level of taxation, specifically a personal income tax, and the DCF ROE incorporates investor-level taxes. Thus, because the Private Owners incur only one level of taxes on Trailblazer’s income and the DCF ROE already includes a level of taxation, providing the Private Owners an income tax allowance in the Trailblazer cost of service would compensate the Private Owners twice for their single level of taxation. FERC also preliminarily found that it is proper to include an income tax allowance in Trailblazer’s rates for the part of investor supplied capital coming from its parent corporation, which does pay corporate taxes. In summary, FERC found that:
FERC emphasized that these findings, which address complex factual and policy matters, are preliminary and may change based upon subsequent evidence and argument from the ongoing administrative law judge hearing where these issues are to be fully litigated.
On April 19, 2018, FERC issued Order No. 845 which revised its pro forma Large Generator interconnection Procedures (LGIP) and pro forma Large Generator Interconnection Agreement (LGIA) to improve certainty for interconnection customers (ICs), promote more informed interconnection decisions, and enhance the interconnection process. In Order No. 845, FERC adopted ten different reforms in three general categories. First, in order to improve certainty for ICs, Order No. 845: (1) removed the limitation that ICs may only exercise the option to build a transmission provider’s (TP) interconnection facilities (sole use facilities from ownership demarcation to the point of interconnection) and stand-alone network upgrades (network upgrades that an IC may construct without affecting day-to-day operations of the transmission system) in instances when the TP cannot meet the dates proposed by the IC (with this new rule, the IC has unilateral decision-making on the option to build TP’s interconnection facilities and stand-alone network upgrades); and (2) required that TPs establish interconnection dispute resolution procedures that allow a disputing party to unilaterally seek non-binding dispute resolution. Second, to promote more informed interconnection decisions, Order No. 845: (1) required TPs to outline and make public a method for determining contingent facilities; (2) required TPs to list the specific study processes and assumptions for forming the network models used for interconnection studies; (3) revised the definition of “Generating Facility” to explicitly include electric storage resources; and (4) established reporting requirements for aggregate interconnection study performance. Third, Order No. 845 aimed to enhance the interconnection process by: (1) allowing an IC to request a level of interconnection service that is lower than its generating facility capacity; (2) requiring TPs to allow for provisional interconnection agreements that provide for limited operation of a generating facility prior to completion of the full interconnection process; (3) requiring TPs to create a process for ICs to use surplus interconnection service at existing points of interconnection; and (4) requiring TPs to set forth a procedure to allow TPs to assess and, if necessary, study an IC’s technology changes without affecting the IC’s queued position.
FERC received twelve requests for rehearing or clarification of Order No. 845. FERC granted rehearing regarding the option to build reform to: (1) require that TPs explain why they do not consider a specific network upgrade to be a stand-alone network upgrade; and (2) allow TPs to recover oversight costs related to the interconnection customer’s option to build. FERC also granted rehearing regarding the surplus interconnection service reform to explain that FERC does not intend to limit the ability of RTOs/ISOs to argue that an RTO/ISO variation from FERC’s surplus interconnection service requirements is appropriate. FERC also found that, regarding the reform for requesting interconnection service below a generating facility capacity, an IC may propose control technologies at any time in the interconnection process that it is permitted to request interconnection service below generating facility capacity. Additionally, FERC granted clarification regarding the option to build by finding that: (1) the Order No. 845 option to build provisions apply to all public utility TPs, including those that reimburse the interconnection customer for network upgrades; and (2) the option to build does not apply to stand-alone network upgrades on affected systems (another system that is affected by the interconnection). FERC also granted clarification with regard to transparency regarding study models and assumptions to find that: (1) TPs may use FERC’s critical energy/electric infrastructure information (CEII) regulations as a model for evaluating entities that request network model information and assumptions; and (2) the phrase “current system conditions” does not require TPs to maintain network models that reflect current real-time operating conditions of the TP’s system. Regarding the interconnection study deadlines reform, FERC granted clarification that the date for measuring study performance metrics and the reporting requirements do not require TPs to post 2017 interconnection study metrics – the reporting requirements will begin in 2020. Regarding requesting interconnection service below generating facility capacity, FERC granted clarification that a TP must provide a detailed explanation of its determination to perform additional studies at the full generating facility capacity for an IC that has requested service below its full generating facility capacity.
Further information on the Option to Build – in 2009, FERC allowed MISO to directly assign to ICs 90% of the costs for network upgrades rated 345 kV and above (with the remaining 10% recovered on a system-wide basis) and 100% of the costs for network upgrades rated below 345 kV. In addition, the MISO OATT provided TPs two options for recovering network upgrade capital costs from ICs – 1) the IC would fund the network upgrades prior to construction, and the TP would not refund the non-reimbursable portion of this capital (the 90% or 100%) and would neither include the capital in its rate base nor charge the IC a return on this capital (as it is fully funded by the IC); and 2) the TP would fund the construction of the network upgrades (either initially or via reimburse IC after construction) and then recover the ICs portion over time through periodic network upgrade charges that include a return on the capital investment. The TPs had unilateral selection rights.
In June 2015, FERC initiated a complaint against MISO relating to these network upgrade funding options because FERC determined that allowing MISO TPs to unilaterally select transmission owner funding may be unjust, unreasonable, unduly discriminatory and may increase costs of interconnection service with no corresponding increase in service. In December 2015, FERC directed MISO to revise its tariff to remove the ability of a transmission owner unilaterally to elect to fund network upgrades. FERC found that such revision would not deprive MISO transmission owners of the opportunity to earn a return because, pursuant to the IC funding approach, the TPs make no investment on which they are entitled to a return.
After the TPs appealed the FERC decision to the D.C. Court of Appeals (D.C. Circuit), the DC Circuit vacated and remanded the decision, finding that FERC had not adequately responded to MISO TPs concerns that IC funding compels TPs to construct, own, and operate facilities without compensatory network upgrade charges, thus forcing them to accept additional risk without corresponding return as essentially non-profit managers of network upgrade facilities. The D.C. Circuit found that the MISO TPs would have to assume certain costs that are never compensated such as liability for insurance deductibles and litigation, including environmental and reliability claims. Moreover, the D.C. Circuit stated that the orders at issue suggest that FERC does not believe that the TPs are entitled to earn a return on capital for network upgrades funded by the ICs despite TP’s assumption of such costs. For these reasons, the D.C. Circuit stated that FERC must explain how investors could be expected to underwrite the prospect of potentially large non-profit appendages with no compensatory incremental return. FERC eventually restored in the MISO OATT the TPs unilateral right to determine the funding of the network upgrades.
The MISO TPs argued on rehearing in this generator interconnection reform proceeding that providing ICs the unilateral option to build interconnection facilities and stand-alone network upgrades was contrary to the regulatory compact and the D.C. Circuit decision. They asked for rehearing or, if denied, they requested that FERC clarify that TPs may fund construction costs incurred for the option to build facilities and then charge the IC a return, like the current provision in the MISO OATT. In other words, the TPs requested that their unilateral right to fund network upgrades be extended to the facilities for which the IC, under the reforms, now has a unilateral right to build. In Order 845-A, FERC denied the requests, stating that its reforms are not in conflict with D.C Circuit decision as the concerns identified in the D.C. Circuit decision pertain solely to unique features of MISO’s OATT. Specifically, the D.C. Circuit’s primary concern was with FERC’s requirement that there be mutual agreement between the TP and the IC before the TP can elect to fund the interconnection, which would mean that the IC could effectively prevent the TP from assessing a network upgrade charge and receiving a return on its investment. FERC said its current reforms do not deprive TPs of the ability to earn a return of, and on, network upgrades, including stand-alone network upgrades. On the contrary, Order No. 2003 (initially establishing the more limited option to build in effect prior to Order 845) established a mechanism that explicitly allows TPs to earn a return of, and on, the costs of network upgrades that they fund. The concerns the D.C. Circuit identified are present only in MISO because MISO’s interconnection pricing policy is a unique variation from Order No. 2003 under which MISO directly assigns 90% or 1004 of the network upgrade cost responsibility to ICs. FERC denied the requests because they are essentially requesting FERC to allow MISO to deviate from the requirements outlined in Order No. 845 based on MISO’s interconnection pricing policy, which is itself a deviation from Order No 2003. FERC stated that If MISO wishes to make such a request, it should do so when it submits its Order No. 845 and 845-A compliance filing, and FERC will consider it then.
FERC reiterated in this Order that it expanded the option to build for ICs as ICs have incentives greater than those of TPs to reduce network upgrade costs. FERC also found that concerns that the option to build will compromise system reliability are misplaced because they ignore the safeguards for reliability, including potential for NERC violations. already in place for the existing option to build. If the IC exercises its option to build, FERC provided for the TP’s recovery of costs of executing the responsibilities enumerated for TPs (project oversight, for example) and expects the TP and IC to negotiate this amount and clearly state it in the LGIA. Reporting under the reforms will begin in 2020.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.