​On October 15, 2029, in Docket No. ER20-1783, FERC approved a request by NEET MidAtlantic Indiana for a formula rate that accommodates its acquisition of certain transmission facilities from Commonwealth Edison Company of Indiana, Inc. (ComEd) and rejected its request to establish a regulatory asset for transaction costs related to the acquisition.  FERC approved the tariff changes to become effective upon the date NEET MidAtlantic Indiana becomes a transmission-owning member in PJM.  FERC denied NEET MidAtlantic Indiana’s request for pre-approval to record the transaction costs as regulatory assets as the transaction costs at issue here are not the type of incentives, such as formation and pre-commercial costs related to competition for transmission enhancements as part of the RTEP process, that the Commission has previously found further the policy goal of facilitating the participation of nonincumbent transmission developers in transmission planning processes, thereby encouraging competition.  Rather these costs are associated with the acquisition of existing transmission assets.  FERC’s policy is to accept acquisition adjustments in rate base, and thus allow their recovery, only if utility can show that “the investment decision is prudent and if it can demonstrate that the acquisition provides measurable benefits to ratepayers.”  To recover such acquisition adjustments, the utility must show specific, tangible, non-speculative, quantifiable benefits in monetary terms, which NEET MidAtlantic Indiana did not do.  

​On September 17, 2020, in Docket No. EL20-51, FERC granted Southern California Edison (SCE) the transmission abandonment and CWIP incentives for its Riverside Project, which includes the construction of a new 230 kV substation and associated facilities; approximately 10 miles of 230 kV double-circuit transmission lines, of which approximately four miles will be placed underground; and new telecommunications equipment between the new substation and existing substations (Project).  FERC granted abandonment incentive as SCE faces risks and challenges in the development of the Project, including certificates of convenience and necessity and wetland permits from the U.S. Army Corps of Engineers.  FERC stated that the abandonment incentive will protect SCE, should the Project be abandoned for reasons beyond SoCal Edison’s control.  If the Project is abandoned for reasons beyond SCE’s control, SCE would be required to make a filing under section 205 of the FPA to demonstrate that the costs were prudently incurred before it can recover any abandoned plant costs.  In such a proceeding, abandoned plant cost recovery is available for 100% of prudently incurred project costs expended on or after the date of issuance of this order.  In the event SCE seeks abandoned plant recovery for the period prior to the issuance of this order, SCE would be eligible to seek recovery of 50% of its prudently incurred costs.
 
FERC granted the CWIP Incentive as FERC has found that allowing companies to include 100% of CWIP in rate base would result in greater rate stability for customers by reducing the “rate shock” when certain large-scale transmission projects come online.  With the Project expecting to cost $581 M and not expected to go into service until 2026, FERC found that granting the CWIP incentive to SCE is consistent with Order No. 679.  FERC also stated in its Order that its accounting regulations provide procedures to ensure that customers will not be charged for both capitalized AFUDC and corresponding amounts of CWIP in rate base and its determination to grant SCE the CWIP Incentive is conditioned upon SCE fulfilling FERC’s requirements for CWIP inclusion for the Project in its future FPA section 205 filings. 

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.

​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.

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.  

​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 ER19-303, FERC awarded Duquesne the Abandonment Incentive and CWIP in rate base for a PJM project named the Beaver Valley Deactivation Transmission Project.  The Project is part of a suite of projects needed to address reliability violations resulting from FirstEnergy’s intent to deactivate about 4,000 MW of nuclear generation between May 31, 2020 and October 31, 2021 (four generation facilities are expected to be deactivated, including Davis-Besse Unit 1, Beaver Valley Unit 1, Beaver Valley Unit 2, and the Perry Unit). The Beaver Valley Units 1 and 2 are located within Duquesne’s service territory in southwestern Pennsylvania.  The Project consists of constructing a new Elrama 135 kV substation, connecting seven 138 kV transmission lines to the new substation, reconductoring several transmission lines, establishing a new circuit, and constructing transmission tie lines from the new Elrama substation to a FirstEnergy substation.  Duquesne estimates that the Project will cost $38.4 million and has a projected in-service date of June 1, 2021. 

In ER19-297, FERC awarded Mid-Atlantic Interstate Transmission, LLC (MAIT) and West Penn Power Company (West Penn) the Abandonment Incentive for transmission upgrades, which comprise the Generator Deactivation Project, a PJM project needed to address reliability violations resulting from the same nuclear retirements described above.  The Generator Deactivation Project is estimated to cost $144.4 million and will include three transformer replacements, construction of a new substation and transmission lines, and reconductoring of existing transmission lines and terminal equipment enhancements.  The Generator Deactivation Project has a projected in-service date of June 1, 2021.
FERC also confirmed that both Duquesne and MAIT and West Penn are eligible to seek recovery of 50 percent of their portion of prudently-incurred abandonment costs, net of the closing out of the transaction and sale of associated assets, for both projects expended prior to the date of issuance of this order. However, such recovery, along with any recovery pursuant to the Abandonment Incentive, is subject to a future filing establishing the justness and reasonableness of including such costs in rates. 
​
Duquesne did not propose accounting procedures to ensure that customers will not be charged for both capitalized AFUDC and corresponding amounts of CWIP proposed to be included in rate base and must do so on compliance.  

On November 27, 2018 in Docket No. ER18-2510, FERC approved an Abandonment Incentive requested by First Energy for an electric transmission project in PJM for which they are partially responsible to build and won.  The Abandonment Incentive provides for 100% recovery of prudently-incurred abandonment costs if the project is abandoned or cancelled for reasons beyond the transmission developer’s control.  FERC also confirmed that First Energy is eligible to seek recovery of 50 percent of prudently incurred project costs expended prior to a Commission order granting the Abandonment Incentive. 
​
First Energy sought the same Abandonment Incentive previously approved for Transource, BGE, and PECO for the project – other entities responsible to build and own portions of the project.  Specifically, First Energy requested the Abandonment Incentive to recover 100 percent of their prudently incurred costs, including plant costs, real estate procurement costs (including any losses incurred on the future sale of real estate), pre-commercial development costs, and all related costs, if the project is abandoned or cancelled for reasons beyond their control.  First Energy stated that that it faces several risks in developing and constructing the project that are beyond its control, including permitting risks in two jurisdictions (Pennsylvania and Maryland), the risk that PJM may cancel the project due to changed system needs or economics, and completion risks arising from other transmission owners having development and construction responsibility for different parts of the project. 

FERC has found that transmission projects approved as baseline upgrades and included in PJM’s Regional Transmission Expansion Plan (RTEP) are entitled to the rebuttable presumption, as established under Order No. 679, if the facilities will either ensure reliability or reduce the cost of delivered power by reducing transmission congestion.  The project under consideration here received approval as a baseline project through the RTEP process.  In this case, FERC found that there was a nexus between the incentive sought and the investment made and that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant….” as First Energy demonstrated that the project faces substantial risks and challenges because it will cross several jurisdictions, require multiple layers of governmental approvals, is an interdependent part of a single integrated project, and that the larger project previously was found to face substantial risks and challenges.   Prudence determinations would be made based upon a separate filing pursuant to FPA section 205 if First Energy seeks to recover any abandoned plant costs at which time First Energy would be required to demonstrate that the abandonment or cancellation of the project was beyond its control.