​On July 22, 2020, in EL20-58, AEP requested FERC to determine that its Middle Creek energy storage project (Middle Creek) is eligible for cost-of-service recovery through AEP’s transmission formula rates, and specifically through the transmission accounts designated for such projects in Order No. 784.  AEP asserts that Middle Creek is a transmission asset that has undergone full review through the PJM stakeholder process, and AEP does not propose that the project will participate in wholesale energy or capacity markets or provide ancillary services, and thus AEP does not propose to recover market-based revenues through those markets.  Middle Creek is an innovative battery storage project that will provide an efficient and cost-effective solution to address outages on the AEP transmission system. AEP carefully analyzed the cause of those outages and potential alternative solutions, including tearing down and rebuilding 14 miles of transmission line segments, and determined that a properly-sized battery storage solution would reduce customer exposure to the transmission outages at far less than the cost of the transmission rebuild project. The project went through the appropriate PJM stakeholder process, wherein it underwent the same review process as would a traditional wires solution. As such, AEP asserts that the Middle Creek Project is appropriately deemed a transmission project, consistent with the definition of a Transmission Facility under the PJM Tariff.  

On August 17, 2020, in Docket No. ER20-1068, FERC granted the Dayton Power and Light Company the CWIP and Abandonment incentives for a suite of projects resulting from the PJM planning process or subject to Ohio state siting approval.  In addition, Dayton had requested the 50-basis point RTO Adder as it is a member of the PJM RTO and has turned functional control of its transmission assets to PJM.  FERC  accepted the RTO Adder part of request and suspended it for a five month period, subject to refund and the outcome of a paper hearing to explore whether  Dayton has shown that its participation in PJM or another RTO is voluntary, as required for it to be entitled to the adder, or if such participation is mandated by Ohio law.  Initial responses to the questions in the Appendix (see below) of this order are due within 60 days of the date of this order and reply comments to the initial responses are due within 30 days of the initial responses.  FERC requested that parties respond to the following two questions:
 
1.   Is there an arrangement under which Dayton could withdraw from an RTO and comply with the Ohio law, while not being eligible for an RTO Participation Adder?  If so, please describe that alternative arrangement.  If not, please explain why not.
2.   Explain how any alternative arrangement identified in response to Question 1 would comply with the Ohio Revised Code section 4928.12, but would not at the same time qualify for incentives for joining a Transmission Organization under section 35.35(e) of the Commission’s regulations, 18 C.F.R § 35.35(e) (2019).  As part of your answer, please: (1) explain why such arrangement would not qualify for an incentive under section 35.35(e) of the Commission’s regulations; and (2) address each of the 9 requirements for such an arrangement specified in Ohio Revised Code section 4928.12(B) and explain how the arrangement satisfies each such requirement.
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Commissioner Glick dissented in part because he felt that the record FERC is clear that Ohio law requires The Dayton Power and Light Company (Dayton) to be a member of a Transmission Organization.  As a result, there is nothing for the Commission to incentivize by awarding an additional ROE for Transmission Organization membership.  Consistent with Commission precedent, that alone should be more than enough for us to reject this aspect of Dayton’s filing.  Commissioner Danly concurred in the ruling on the RTO Participation Adder, even though the issue set for hearing on the RTO Participation Adder is a legal question that likely could be resolved without a hearing.  Although he would have ruled on that question now, he acknowledged that it is within the Commission’s discretion to set the matter for hearing instead.  Further, if he were to join in Commissioner Glick’s dissent, that would cause a 2-2 split on The Dayton Power and Light Company’s request for the RTO Participation Adder.  It would then go into effect by operation of law without further consideration of the legal question being set for hearing.  By concurring in the decision to set the RTO Participation Adder for hearing, that outcome was avoided.

​On August 20, 2020 in Docket No. EL20-65, the NYISO requested that FERC confirm that the NY Transmission Owners (NYTOs) have a right of first refusal to build, own, and recover the costs of upgrades to their existing transmission facilities and that this right encompasses upgrades proposed as part of another Developer’s transmission project that is selected by the NYISO to be included in its regional plan.  The NYISO also requested that FERC confirm that if a NYTO exercises its right to build, own, and recover the costs of an upgrade that is included in another Developer’s proposed transmission solution that was selected by the NYISO, the NYTO should be treated under existing OATT provisions as the Developer for the upgrade portion of the project, except that the voluntary cost containment provisions would not apply.  Finally, the NYISO requested that FERC clarify two specific points regarding the definition of “upgrade.” The OATT includes the Order No. 1000-A definition, which distinguishes an upgrade that may be subject to a right of first refusal from an entirely new transmission facility that must be subject to competition. However, the distinction between an upgrade and an entirely new transmission facility is not always clear and the ambiguity is expected to result in disputes given the likelihood that transmission projects addressing needs in New York will involve modifications to existing transmission facilities within existing rights of way.  The NYISO requested that FERC clarify two specific points – would a new transmission facility that requires the retirement and decommissioning of a NYTOs existing transmission facilities and that connects to the transmission system in a different configuration constitute an upgrade and, if the facility would be treated as a new transmission facility, would the retirement or decommissioning of the existing transmission facilities require the agreement of the NYTO that owns the facilities or a state regulatory or court ruling authorizing the retirement or decommissioning?  

In June 2020, FERC Staff issued a report on barriers and opportunities for high voltage transmission to the Committees on Appropriations of Both Houses of Congress.  Staff concludes that high voltage transmission can improve the reliability and resilience of the transmission system by allowing utilities to share generating resources, enhance the stability of the existing transmission system, aid with restoration and recovery after an event, and improve frequency response and ancillary services throughout the existing system. High voltage transmission also provides greater access to location-constrained resources in support of renewable resource goals. It also offers opportunities to meet federal, state and local policy goals.  Staff found that while transmission development opportunities exist, there are also barriers which make development of high voltage transmission challenging. For instance, siting of high voltage transmission, generally an area of state jurisdiction, requires navigating each state process or multiple state processes for an interstate high voltage transmission facility. Various other authorizations and reviews are also generally required at the federal, state, and local levels. Additionally, the time required to develop a high voltage transmission facility that meets mandatory Reliability Standards, maximizes system benefits, and strikes a balance among interested stakeholders (including states) can be in excess of a decade.  Specific to the nation’s transportation corridors, there are several federal and state actions intended to create opportunities for energy infrastructure development, including high voltage transmission, in these corridors. However, future transmission development in existing transportation corridors may be restricted by routing limitations, including state and local prohibitions and restrictions, and safety and technical considerations.  ​

​On August 6, 2020, in Docket No. EL20-60, Pacific Gas and Electric Company (“PG&E”) filed for a Petition for Declaratory Order (“Petition”) for 100% recovery of prudently-incurred abandoned plant costs (if abandoned for reasons outside the control of PG&E) for PG&E’s portion of two significant reliability-driven transmission projects approved in CAISO’s 2018-2019 Transmission Plan: (1) the Gates 500 kV Dynamic Reactive Support Project (“Gates Project”) and (2) the Round Mountain 500 kV Area Dynamic Reactive Support Project (“Round Mountain Project”) (collectively “Projects”).  Under its competitive solicitation process, the CAISO selected LS Power Grid California, LLC (“LS Power Grid”) as the Project Sponsor for the Gates Project on January 17, 2020, and the Round Mountain Project on February 28, 2020.  As the incumbent transmission owner, PG&E is required to complete significant supporting work for the Projects.  For the Gates Project, PG&E is responsible for all system upgrades, including telecommunications and protection system upgrades using advanced fiber optic technology and for all equipment installation to connect the Gates voltage control equipment to the Gates 500 kV bus on the PG&E side of the point of change of ownership switch.  For the Round Mountain Project, PG&E will be responsible for various project specific telecommunications and protective system upgrades at both the target substations and adjacent substations. For example, new tripping schemes will need to be installed to account for voltage support equipment operations in non-normal system configurations. This work is extensive, often entails significant work at other, more remote, substations and will not be known with certainty until much later in the project design process as detailed design comes to completion.  PG&E asserts that since LS Power Grid received the abandonment incentive for these two projects, PG&E is entitled to the abandonment incentive for its related investments as PG&E faces the same risk and challenges as LS Power Grid.  Finally, the substantial cost, long-lead time for equipment, risk of cost escalation, and risk of a shortage in skilled labor are all risk factors that could lead to the cancellation of one or both projects, exposing PG&E to the risk of unrecovered costs without the Abandoned Plant Incentive.  

After a MISO filing in December 2019, several protests, comments and answers, a technical conference and responsive pleadings, FERC approved, effective August 11, 2020, in Docket ER20-588, changes to the MISO OATT that provide for storage to be treated as a transmission asset for transmission planning and project selection.  FERC required MISO to add to its Tariff certain clarifications provided by MISO through its post-technical conference comments. 
MISO proposed a new section to its Tariff, which included:  (1) an evaluation process for storage as a transmission only asset (“SATOA”) to be included in the MTEP as the preferred solution to a Transmission Issue; (2) the development of operating guides for each SATOA; (3) a description of the market activities and market impacts of a SATOA; (4) a description of the mechanism under which a SATOA recovers costs; and (5) a description of how MISO will consider a SATOA’s impacts on resources in the generator interconnection queue.  MISO asserted that, consistent with FERC precedent:  (1) the SATOA will be operated in a manner that preserves MISO’s independence because the SATOA owner is responsible for maintaining the necessary state of charge to serve the transmission function for which it was approved in the MTEP; (2) MISO will exercise functional control of the SATOA for transmission purposes only, and will not be responsible for buying power to energize the project; (3) any revenues received by the resource for charging/discharging to meet its transmission obligations are properly credited back to the transmission function; and (4) the project must be identified as the preferred solution to a Transmission Issue.  MISO also stated that the SATOA will not participate in its markets but will use market settlement mechanisms to settle the charging and discharging functions performed under MISO functional control and direction. 

Evaluation Process:  MISO will include a SATOA in the MTEP or select a SATOA in the MTEP for purposes of cost allocation only as the preferred solution to a Transmission Issue identified in MISO’s regional MTEP process.  More specifically, a storage facility will not qualify as a SATOA unless it is needed to resolve a discrete, non-routine transmission need (such as N-2 or stability issues) that only can be addressed by an asset under MISO’s functional control, and not by a resource operating in MISO’s markets.  SATOAs must meet the same qualification requirements as traditional transmission solutions for all existing Commission-approved project types.  SATOAs will not have any competitive advantage as transmission solutions in the MTEP process and they will be evaluated in the same manner as traditional transmission solutions.  In addition, MISO’s approach applies to SATOAs the cost allocation method applicable to existing MTEP project types, eliminating the need to establish a stand-alone cost allocation method if SATOAs were evaluated outside of the existing transmission project type framework.  SATOAs will be required to be a transmission owner and a party to the Transmission Owners Agreement, and adhere to all the rights, responsibilities, and obligations that are attendant to that role – including the obligation to construct and the requirement to transfer functional control to MISO. 

Cost Recovery:  SATOAs are eligible for cost recovery consistent with the cost recovery for its MTEP project type under Attachment FF of MISO’s Tariff (i.e., Baseline Reliability Project, Other Project, etc.).  MISO proposes that cost recovery for a SATOA under transmission rates will be limited to the cost of the maximum capacity needed to address the Transmission Issue and will be pro-rated on that basis if a SATOA of higher capacity is proposed, approved for inclusion in the MTEP, and installed, so that transmission customers do not subsidize any excess capacity.  Transmission projects recommended through the MTEP process, and listed in Appendix A of the MTEP report (Appendix A projects), currently have their costs recovered through Attachments O, GG, and MM of the MISO Tariff, and that SATOA projects would follow a similar process.  In its Order, FERC, as provided in Order No. 784 and the Commission’s regulations and related accounting guidance, stated that MISO transmission owners must record the transmission storage asset in Account 351 (Energy Storage Equipment - Transmission), expenses associated with charging the transmission storage asset in Account 555.1 (Power Purchased for Storage Operations), and record the revenues associated with discharging the asset in the appropriate revenue accounts.  The expenses incurred that are associated with the operations and maintenance of the transmission storage asset are to be recorded in Account 562.1 (Operation of Energy Storage Equipment) and Account 570.1 (Maintenance of Energy Storage Equipment), respectively.  The Commission’s regulations further provide that, to the extent the revenues associated with discharging the storage asset are associated with net settlements for exchange of electricity or power, such revenues are to be recorded in Account 555.1, a production account not included in the MISO transmission formula rates.  Accordingly, a MISO transmission owner that develops a SATOA will need to make a filing pursuant to FPA section 205 to update its Attachment O with a line item to ensure any revenues or expenses associated with the discharging and charging of the SATOA are treated in a manner consistent with the treatment of costs associated with the project category in transmission rates.  Further, a MISO transmission owner is required to include a workpaper with its annual informational filing showing the sales of the charging and discharging of the storage asset for transparency purposes.

​Dissenting:  Commissioner Danly dissented as he sees the FERC Order impermissibly blurring the line between generation and transmission facilities.  Because storage facilities discharge energy into the MISO system, they serve a generation function.  He disagrees that such assets are transmission assets and that they should receive recovery as transmission assets.  He is concerned that opening the transmission door to storage facilities will result in other generators seeking similar treatment.  He states that storage facilities can provide the transmission-related services when they offer the best solution to a transmission constraint.  However, provision of such services should be through the sale of an ancillary service in competition with other generation facilities, as is done today for ancillary services such as reactive power and frequency control.