Background:  In late 2015, FERC initiated a Section 206 investigation of the New England transmission formula rate.  FERC found that the existing formula rate lacked transparency, may not be treating certain cost components correctly, and may not synchronize local and regional revenue requirements such that overcollections could be occurring. After over two and one-half years of settlement negotiations with the six New England state regulators and municipal customers in Massachusetts, along with FERC trial staff, the New England Transmission Owners (“NETOs”) filed a settlement in August 2018.  The Settlement is supported by the consumer advocates for Massachusetts, Connecticut and Maine as well as NESCOE.  The consumer advocates and the states had technical experts and experienced counsel to assist them in the negotiations.  ISO-NE stakeholders approved the Settlement by a vote of 96% in favor.  The Massachusetts municipal customers and FERC trial staff filed comments opposing the settlement. 

FERC may approve contested settlements under the following conditions, based upon the Trailblazer case: (1) the Commission may make a decision on the merits of each contested issue; (2) the Commission determines that the settlement provides an overall just and reasonable result; (3) the Commission determines that the benefits of the settlement outweigh the nature of the objections, and the contesting parties’ interests are too attenuated; and (4) the Commission determines that the contesting parties can be severed longstanding principle that it is the “end result” of the rate setting process that counts, not each individual component of the rate. 
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FERC Order dated May 22, 2019:  In this Order, FERC rejected the settlement and remanded the case back to the Chief ALJ for hearing procedures to resume.  FERC determined that it was unable to approve the settlement using the Trailblazer precedent.  As for item 1, FERC found that the record is inadequate to weigh each issue individually.  For example, the proposed formula rate templates include numerous references to an “Attachment,” but the attachments have not been provided for review; the allocators are not verifiable or transparent; and the formula rate templates include numerous external references, which are not clearly defined.  As another example, the proposed formula rate templates alternate between using five-quarter average balances and beginning-of-year and end-of year average balances to calculate rate base items without explanation.  As for item 2, FERC could not determine whether the overall settlement package falls within a just and reasonable range, because the record lacks crucial information, such as the method or derivation of the allocation factors, information to determine whether several components of the rates are discretionary and in excess of the cost of providing transmission service, preventative controls for double recovery of certain components of the rates, and how the rates exclude non-transmission amounts from the rates.  Moreover, Contesting Municipals have provided evidence suggesting that the Settlement will leave them worse off than if the issues were litigated as they provide detailed calculations, testimony, and workpapers indicating that the Settlement’s proposal to retain existing service company allocations results in an increase in the transmission revenue requirement of $42.5 million over the transmission revenue requirement that would result if the Settlement used allocations that are known and measurable.  As for item 3, FERC found that the record was insufficient to determine whether the Settlement’s benefits outweigh the objections to it; in fact, Contesting Municipals present evidence that there is more harm than benefit.  For item 4, FERC determined that the issues raised by the Contesting Municipals were not severable because they raise valid concerns involving the overall costs of transmission service under the Tariff that apply to all parties.  For these reasons and based on the overall lack of necessary detail and transparency throughout the Settlement, FERC was unable to approve the Settlement and remanded this proceeding to the Chief Administrative Law Judge to resume hearing procedures.  

On March 15, 2019, in Docket No. ER19-1359, the United Illuminating Company (UI), an affiliate of Avangrid, requested rate incentives for a substation replacement project.  UI’s Pequonnock Substation Project will replace the existing Pequonnock substation and will include (1) a new 115-kV/13.8-kV gas insulated substation; (2) the relocation and installation of five existing 115-kV overhead transmission lines; and (3) the relocation and installation of two 115-kV underground high-pressure gas filled cables and one underground XLPE cable, each ranging in length from about 500 feet to 730 feet. The Pequonnock Substation Project is approximately a $101.6 million electric transmission investment and is expected to be placed in service on or before December 1, 2022.  It will deploy smart grid communications-enabled technology and a resilient hardened substation design to improve the reliability of ISO-NE’s bulk electric system and to protect and maintain the transfer of uninterrupted power flow along the coast of southwestern Connecticut bordering Bridgeport Harbor.
 
UI requested (1) 100 percent recovery of prudently incurred costs in the event the Pequonnock Substation Project is abandoned, in whole or in part, for reasons outside of UI’s reasonable control (“Abandoned Plant Incentive”); (2) inclusion of 100 percent Construction Work in Progress in rate base (“CWIP Incentive”); and (3) a 50 basis point return on common equity (“ROE”) incentive adder (“ROE Incentive Adder”) for increased risks and challenges prompted by UI’s deployment of advanced technology and construction and operation of a substation that includes a resilient design.  The Project is significant for UI as it represents over 12% of UIs existing transmission investment base. 
 
On May 14, 2019, FERC found that the Pequonnock Project has received construction approval from an appropriate state siting authority that considered whether the project ensured reliability or reduced congestion and therefore the Project is entitled to the rebuttable presumption established in Order No. 679 and satisfies the section 219 requirement that a project ensure reliability or reduce the cost of delivered power by reducing transmission congestion.  As a result, FERC granted the risk reducing incentives (Abandoned Plant and CWIP incentives) but denied the request for a 50-basis point ROE Incentive Adder.  As for the ROE Incentive Adder, FERC found that United Illuminating failed to make the first demonstration set forth in the 2012 Policy Statement in that it has not shown that the Pequonnock Project 1) will relieve chronic or severe grid congestion that has had demonstrated cost impacts to consumers; (2) will unlock location constrained generation resources that previously had limited or no access to the wholesale electricity markets; or (3) will apply new technologies to facilitate more efficient and reliable usage and operation of existing or new facilities.  United Illuminating has not shown that its use of smart grid technology or “hardened resilient design” reflects the application of new technologies to facilitate more efficient and reliable usage and operation of existing or new facilities.  Lastly, United Illuminating also has not demonstrated that the Pequonnock Project otherwise faces risks and challenges either not already accounted for in United Illuminating’s base ROE or addressed through risk-reducing incentives.

​On April 17, 2019 in Docket No. EL19-69, Alternative Transmission Inc. (ATI) requested that FERC issue an order confirming that (1) the alternative transmission facilities and services described in its petition provide “transmission of electric energy in interstate commerce” subject to FERC’s jurisdiction under Parts II and III of the Federal Power Act (FPA) and (2) ATI as the owner or operator of the described facilities will be a “public utility” under Parts II and III of the FPA.  ATI plans to transmit electricity across state lines without the use of wires.  It proposes to do so by constructing electric energy transfer stations—charging and discharging—at locations in the continental United States. At the charging stations, electric energy generated by unaffiliated entities will be transferred to a mobile medium--e.g., a shippable container of an electrically chargeable, dischargeable, and rechargeable medium. The charged mobile medium then will be transported across state lines by rail (and possibly tractor-trailer, boat or airplane, or any combination of these) to discharging stations at different locations. At the discharging station, the medium in the containers will be available for instantaneous dispatch as instructed, until the charge is depleted and the medium becomes available for recharge.  ATI will deliver electric energy into areas accessible by surface transportation (and possibly water or air) where (1) current or forecast demand for delivered electric energy cannot adequately be met by existing wire transmission corridors, or (2) the ATI’s approach is the most timely or most economical solution for meeting existing or forecast demand. Further applications are conceivable, such as diverting natural gas directly to combustion turbines or combined-cycle generating units constructed at or proximate to the production of those natural gas reserves and generating electricity to charge the media in container cars for transport to markets using neither pipelines nor wires.  Additionally, ATI’s proposal could address widespread power outages from emergencies or disasters or from cyber-attacks or improper maintenance.  Discharging stations can be modular and transported where needed. 
 
There is more information in the ATI filing, including an affidavit further explaining the ATI approach, which can be found at https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14767433.
 

In early May, in Docket No. EL19-70, a group of generators in PJM requested a declaratory order from FERC on several reactive power issues for which there is uncertainty in the FERC methodology.  The generators requested that FERC find the following as to reactive power revenue requirement calculations:
 

1. A merchant generator in PJM can use, as a proxy for its capital structure and return on equity, the capital cost and capital structure determined in PJM’s Commission-approved “Cost of New Entry” study (“CONE Study”). This proxy is already used in PJM’s tariff for its capacity market, and results from a detailed study of the cost of building new merchant generation within PJM.  The alternative measure for capital cost and capital structure traditionally used in reactive power rate cases—that of the interconnecting transmission owner—is a less accurate proxy than the CONE Study, because a merchant generator faces significantly greater risk than a transmission owner, as FERC has repeatedly acknowledged. Thus, a merchant generator requires a different capital structure with a higher cost of debt and a greater return on equity.
2. A generator may include the fixed costs of firm fuel delivery in the calculation of its reactive power rate, like any other fixed operating & maintenance (O&M) cost. These costs reflect infrastructure improvements needed to serve the generator, and not the cost of fuel itself. Accordingly, these costs should be treated just like other fixed costs incurred by the generator, a portion of which may be included in the fixed charge rate used to determine the annual revenue requirement.
3. FERC provide guidance on the type of evidence on which a merchant generator can rely to show the construction costs incurred by its Engineering, Procurement, and Construction (“EPC”) Contractor. Increasingly, merchant generation plants are turn-key investments constructed entirely by an EPC Contractor, which is paid an all-in amount for the plant under a closed-book contract.  A merchant generator seeking reactive power rate recovery for such a plant is faced with the challenge of identifying which of the EPC Contractor’s costs should be assigned to the major equipment categories comprising the reactive power investment, when the merchant generator itself typically has no insight into the specific amounts incurred by the EPC Contractor to build different parts of the plant, and when the EPC Contractor does not use, and is not required to use, the FERC Uniform System of Accounts. FERC should declare that a generator, for purposes of its reactive power tariff, may rely on the EPC Contractor’s apportionment of the project costs among the major equipment categories relevant under the AEP methodology. If the resulting accounting entries are within the range of reasonableness as compared to the reactive power tariffs of other similar plants, then the generator should be deemed to have carried its burden.
4. Confirm the types of indirect costs that may be included in a generator’s reactive power tariff. In the Chehalis decision, FERC made clear that indirect costs may be recovered, and FERC approved a subsequent compliance filing setting forth categories of indirect costs that would be recovered.  FERC should issue a declaration stating that the categories of indirect costs set forth in the Chehalis compliance filing and in Bluegrass are, as a general matter, recoverable in a reactive power tariff.
5. FERC should confirm its existing precedent that a generator may seek recovery for its reactive power costs based on its full reactive power capability—rather than the minimum capability required under the PJM tariff.  Though a FERC order holds as much, but the Independent Market Monitor has nevertheless insisted on litigating the issue in recent, and pending, reactive power cases.  FERC’s confirmation of its prior order will prevent unnecessary litigation costs and facilitate settlement. 
6. Concerning the methodology for allocating to reactive power the costs of accessory electric equipment, FERC has established a methodology in its Dynegy decision.  FERC should confirm that this existing precedent remains the Commission’s policy.  This precedent is that a reactive power provider can allocate accessory electric equipment to the generator and exciter using the ratio of generator-exciter auxiliary load to total plant auxiliary load.