On January 21, 2020, in ER20-857, MISO and the MISO TOs (“MISO”) proposed changes to the cost allocation for Market Efficiency Projects. These changes result from an extensive stakeholder process and are described generally below:
On December 17, 2019, in ER20-617, the NYISO proposed changes to its public policy transmission process to establish provisions for cost containment of transmission projects proposed by developers. As detailed in its filing, the NYISO’s proposed revisions will establish: (A) the cost containment mechanisms that a Developer may voluntarily include as part of a proposed Public Policy Transmission Project in the Public Policy Process; (B) how the NYISO will evaluate in a quantitative and qualitative manner cost containment commitments made by Developers to select the more efficient or cost effective transmission solution to a Public Policy Transmission Need; (C) the manner in which cost containment commitments will be implemented as part of the rate recovery for a selected transmission project; (D) the requirements to include any cost containment commitment in the pro forma Development Agreement that must be entered into between the NYISO and the Developer of the selected project; and (E) additional, related tariff revisions.
Cost Cap – needs to include all capital costs except 1) the cost of system upgrades identified through the interconnection process; 2) cost of financing during construction period; 3) unforeseeable environmental remediation and mitigation costs (Note 1); and 4) real-estate costs for existing rights of way which will not be owned by the developer (can be excluded or included by developers).
Note 1: Costs relating to environmental remediation and environmental mitigation that are not anticipated by the Developer or are otherwise indeterminable based upon information reasonably available to the Developer at the time of submission, including any environmental remediation or mitigation costs that cannot be estimated by the Developer without performing an environmental site assessment or investigation . . . . Costs attributable to environmental investigation, remediation, and mitigation that exceed the amount estimated in the Developer’s bid based on, among other things, changes in the extent of known contamination will be considered “unforeseeable environmental remediation and environmental mitigation costs.”
Developers can propose hard cost caps or soft cost caps. Hard cost caps contain an amount over which the developer cannot recover costs from customers. Soft cost caps contain an amount over which the developer will recover less than or equal to 80% of the costs from customers.
NYISO will evaluate developers capital cost containment commitments qualitatively and quantitatively, as with other evaluation metrics.
NYISO proposes to require the Developer of a selected transmission project to file with FERC any Cost Cap that it proposed as part of the rate for its project. It will amend the pro forma Development Agreement between the NYISO and Developer to include the Cost Cap proposed by the Developer of a selected project.
NYISO proposes limited, specified excusing conditions from the Cost Cap. Those conditions are: (i) Transmission Project changes, delays, or additional costs that are due to the actions or omissions of the ISO, Connecting Transmission Owner(s), Interconnecting Transmission Owner(s), or Affected Transmission Owner(s); (ii) a Force Majeure event as defined in the Development Agreement, (iii) changes in laws or regulations, including but not limited to applicable taxes; (iv) material modifications to scope or routing arising from siting processes under Public Service Law Article VII or applicable local laws as determined by the New York State Public Service Commission or local governments respectively; and (v) actions or inactions of regulatory or governmental entities, and court orders.
On December 31, 2019, in ER20-159, FERC approved, subject to two revisions, Pioneer’s request to recover pre-commercial costs related to a transmission project (Pioneer had previously received the pre-commercial cost incentive from FERC). Pioneer is a joint venture formed by AEP and Duke. Pioneer requested that it be allowed to recover approximately $10.0 M of pre-commercial costs incurred for the March 2009 through December 31, 2019 period, including carrying charges, for development of the Greentown-to-Reynolds segment, which Pioneer has deferred as a regulatory asset. Pioneer asserted that the identified pre-commercial operation costs were prudently incurred and properly recorded and categorized as: (1) business services; (2) legal services; (3) FERC regulatory services; (4) Indiana regulatory services; (5) tax services; and (6) carrying costs. Pioneer stated that these prudently incurred costs would have otherwise been chargeable to expense in the period incurred, but Pioneer’s formula rate was not then in effect. Pioneer also asserted that such costs associated with owning and operating facilities that are used to provide utility service are recoverable in rates.
Pioneer proposed to recover approximately $4.4 M in carrying charges for the period March 2009 through December 31, 2019. Pioneer stated that it calculated the carrying charges without the 150 basis point ROE adder (it had previously been granted an ROR Adder for a larger but related project) in accordance with the July 2019 Order. Pioneer stated that the cost of capital used in the determination of the carrying charges is generally based on a hypothetical capital structure reflecting 50 percent equity and 50 percent debt. Pioneer explains that for the period March 2009 through November 11, 2013, the cost of capital reflects an 11.04% ROE (10.54% base ROE approved in Pioneer I plus 50 basis points for RTO participation), and for the period November 12, 2013, through December 31, 2019, it reflects a 10.82% ROE (10.32% base ROE approved for MISO transmission owners in Docket No. EL14-12 plus 50 basis points for RTO participation). Pioneer requested to amortize the pre-commercial operation costs deferred as a regulatory asset over a five-year period beginning on the effective date to be granted by the Commission in the instant filing. Pioneer requests an effective date of January 1, 2020.
In a prior order, FERC authorized Pioneer to utilize a 50 percent debt/50 percent equity hypothetical capital structure until the completion of the project, finding that Pioneer did not provide a sufficient nexus for the use of a hypothetical capital structure beyond the completion of the project. FERC directed Pioneer, upon completion of the project, to adopt a capital structure based upon its actual financing presented in its Form No. 1. In the instant filing, Pioneer proposes to utilize the 50 percent debt/50 percent equity hypothetical structure beyond the completion date of the project, June 24, 2018. However, Pioneer’s Form No. 1 annual update, filed April 15, 2019, shows that Pioneer’s actual capital structure for the year ending 2018 was approximately 51.1 percent debt and 48.9 percent equity. Accordingly, FERC directed Pioneer to submit a compliance filing utilizing Pioneer’s actual capital structure as presented in its Form No. 1 in calculating its carrying charges beginning June 25, 2018. And consistent with the August 2018 order, FERC’s acceptance of Pioneer’s request to use the MISO regional base ROE for the period November 12, 2013 – February 11, 2015 and prospectively from September 28, 2016, is subject to the outcome of the complaint proceedings in Docket Nos. EL14-12 and EL15-45.
On March 13, 2019, in AC19-75, Duke Energy Corporation, on behalf of its six utility operating companies1 (collectively, Duke), filed an accounting request for approval to treat its Cybersecurity Informational Technology-Operational Technology Program (Cybersecurity Program) as a single project for purposes of calculating Allowance for Funds Used During Construction (AFUDC). FERC approved Duke’s request.
Duke requested approval to treat its Cybersecurity Program as a single project for purposes of determining the accrual period for AFUDC and the in-service date for those assets constructed as part of the Cybersecurity Program. Duke seeks confirmation that it may continue to accrue AFUDC on all of the Cybersecurity Program’s costs until all of the deliverables have been tested, found to be used and useful by Duke’s Operations Council, and placed in service after the completion of the entire Cybersecurity Program. Duke states that it will make over $137 million in capital investments as part of its Cybersecurity Program over the next 36 to 42 months across its generation, transmission, and distribution assets to address the increasing threat of cyberattacks. Duke explains that the Cybersecurity Program is designed based on the National Institute of Standards and Technology’s Framework for Improving Critical Infrastructure Cybersecurity, which consists of five core functions—identify, protect, detect, respond, and recover. According to Duke, it will make capital investments and deploy hardware and software to address each of these core functions on an enterprise-wide basis. Duke states that the focus areas of the Cybersecurity Program include safety systems critical to protect customer’s and employee’s safety, reliability systems critical to reliably operate the platforms, and security systems critical to protecting assets and operations as well as to detecting security anomalies across the platforms. Consistent with the Commission’s AFUDC policy, Duke explains that it has assessed whether capital expenditures for the Cybersecurity Program continue to be incurred and activities that are necessary to get the construction project ready for its intended use are in progress for the duration of construction of all of the Cybersecurity Program’s assets. Duke states that, under its Cybersecurity Program, it “will incur a continuous and steady stream of construction activity expenses” through early 2022. According to Duke, the deliverables for each of the NIST Cybersecurity Framework’s five core functions—identify, protect, detect, respond, and recover—involve complementary, interrelated and interdependent technologies and, “[t]o be effective, all the interdependent hardware and software must be implemented across the entire enterprise, which will take the duration of the Program.” Duke asserts that, although the constituent parts of the Cybersecurity Program will be deployed over shorter timeframes, the Cybersecurity Program’s intended use and benefits—to optimize cybersecurity protection across all lines of business—cannot be achieved until the entire Cybersecurity Program is complete. Duke further declares that “no singular Program asset or deliverable will be ready for service or provide protection value until the completion of the entire Program.”
Under the Commission’s existing AFUDC policy in Accounting Release No. 5, AFUDC may continue to accrue on a project as long as two conditions are present: “(1) capital expenditures for the project [continue to be] incurred; and (2) activities that are necessary to get the construction project ready for its intended use are in progress.” Accounting Release No. 5 states that “[c]apitalization of AFUDC stops when the facilities have been tested and are placed in, or ready for, service,” which includes “those portions of construction projects completed and put into service although the project is not fully completed.” The instructions for AFUDC in the Commission’s Uniform System of Accounts also state that: When a part only of a plant or project is placed in operation or is completed and ready for service but the construction work as a whole is incomplete, that part of the cost of the property placed in operation or ready for service, shall be treated as Electric Plant in Service and [AFUDC] thereon as a charge to construction shall cease. [AFUDC] on that part of the cost of the plant which is incomplete may be continued as a charge to construction until such time as it is placed in operation or is ready for service . . . . Duke’s request was to seek clarification that it could treat the Cybersecurity Program as one project.
On December 12, 2019, in ER20-588, MISO proposed a fundamental first step forward for the use of storage resources to maximize the reliability and efficiency of the electric system. The proposed changes to the tariff will allow a storage facility to be selected as a preferred solution to a Transmission Issue in the MTEP process like traditional transmission solutions, such as wires. The use of energy storage to serve multiple functions is of great interest to MISO and its stakeholders, responds to the expressed policy interests of the Commission, and will support the efficiency and reliability of the electric transmission system.
Since March of 2018, MISO has been working with stakeholders to develop Tariff provisions that
address enabling, evaluating, and selecting a storage facility as a transmission asset when, due to
its unique characteristics, the storage as a transmission asset (SATOA) is shown to be the preferred solution to Transmission Issues identified in the planning processes. The proposed protocol outlines the considerations required to compare the SATOA to more traditional transmission assets, including aspects unique to the storage device. Those unique features include degradation of capacity over time,
inverter-based impacts on reliability, and impacts on operating and interconnecting market
resources. This proposal to utilize energy storage as transmission-only assets reflects a fundamental
shift in how these resources are typically added to the system. This foundational first step forward reflected in the filing will not only enable the utilization of more energy storage resources, but the utilization of more energy storage functions to further enhance the robustness of the system.
MISO’s proposal includes:
• A comprehensive Tariff framework for considering SATOA as transmission
• The opportunity for SATOAs to be evaluated in MTEP and be valued like a
• Specific criteria for the evaluation of a SATOA; and
• Provisions that clarify SATOAs are not subject to the Generation Interconnection
Procedures (“GIP”) in MISO Tariff Attachment X.
On August 9, 2019, in Docket No. ER19-2568, Pacific Gas and Electric Company (PG&E) filed a request to recover, through its formula rate, 50 percent of the prudently-incurred costs that it incurred associated with the development of its Diablo Canyon Voltage Support Project (DCVS Project) and its Atlantic – Placer 115kV Transmission Line Project (Placer Project), which were ultimately abandoned. On October 10, 2019, FERC found that PG&E has demonstrated that it qualifies to recover 50 percent of the prudently-incurred project costs for the DCVS Project ($1.1 M) and the Placer Project ($0.3 M) based on the facts and circumstances presented in this proceeding, consistent with Opinion No. 295. Specifically, FERC found that the transmission projects for which PG&E seeks abandonment cost recovery were cancelled based upon CAISO’s determination that the projects were no longer necessary. Thus, we conclude that the abandonment of the two projects was beyond PG&E’s control and that the costs incurred appear to be prudent and have not been shown to be unjust and unreasonable. Protesters objected to PG&E’s proposed 40-year amortization period. In its reply comments, PG&E agreed to change the amortization period to one year. FERC authorized a one-year amortization period, which will reduce potential overall costs by avoiding years of carrying costs and, accordingly, will reduce the impact on PG&E’s overall revenue requirement. FERC explained that the RTO/ISO participation adder does not apply to abandoned transmission projects, which are not turned over to the operational control of an RTO/ISO.
On May 31, 2019, in ER19-2023, Tucson Electric filed, pursuant to sections 205 and 219 of the Federal Power Act (FPA) and part 35 of the Commission’s regulations, a request to recover in rates 100 percent of the prudently-incurred costs that it incurred associated with the development of a 345 kV transmission line between Sahuarita and Nogales, Arizona (Nogales Project), which was ultimately abandoned. Tucson Electric states that, at a minimum, it is eligible to recover 50 percent of the prudently incurred costs associated with the Nogales Project. In its Order dated September 19, 2019, FERC denied Tucson Electric’s request for 100 percent recovery of prudently incurred costs associated with the Nogales Project and granted Tucson Electric’s request for 50 percent recovery, consistent with Opinion 295. FERC accepted and suspended the filing for a nominal period, effective August 1, 2019, subject to refund, and set for hearing and settlement judge procedures the types and level of prudently incurred costs and the appropriate amortization period. FERC denied Tucson Electric request for 100 percent abandoned plant cost recovery on a retroactive basis and many years after it incurred the costs (mostly prior to 2005) and abandoned the project (2014). Tucson Electric developed the Nogales Project (and incurred the associated costs) not only prior to its submittal of the Abandonment Incentive application, but also largely prior to the enactment of section 219 of the FPA and the issuance of Order No. 679.
On October 1, 2018, in EL17-45, the California Public Utilities Commission, the Northern California Power Agency (NCPA), the City and County of San Francisco, the State Water Contractors, and the Transmission Agency of Northern California (collectively, Complainants) filed a request for rehearing of the Commission’s August 31, 2018 order denying the Complaint filed in this proceeding against PG&E on February 2, 2017. The Complaint alleged that PG&E is in violation of its obligation under Order No. 890 to conduct an open, coordinated, and transparent transmission planning process because more than 80 percent of PG&E’s transmission planning is done on an internal basis without opportunity for stakeholder input or review. In the Order on Complaint, the Commission found that the Complainants had not shown that PG&E’s transmission owner tariff is unjust, unreasonable, unduly discriminatory, or unduly preferential because it does not require the asset management projects and activities in question to go through an Order No. 890-compliant transmission planning process (Order on Complaint, 164 FERC ¶ 61,161 at P 65). On September 19, 2019, FERC denied rehearing because the Complainants did not show that PG&E’s asset management projects and activities fall within the scope of Order No. 890’s transmission planning reforms or that failing to include these projects and activities within the Order No. 890 transmission planning reforms results in undue discrimination, violates EPAct 2005 requirements, or is inconsistent with Commission precedent.
FERC denied the Complaint in its initial Order on Complaint, finding that the Order No. 890 transmission planning reforms were intended to address concerns regarding undue discrimination in grid expansion, and to the extent that PG&E asset management projects do not expand the grid, they do not fall within the scope of those reforms. FERC found that the transmission-related maintenance and compliance projects, which it referred to as “asset management projects,” at issue in this proceeding do not, as a general matter, expand the CAISO grid. Instead, asset management projects include maintenance, repair, and replacement work, as well as infrastructure security, system reliability, and automation projects that PG&E undertakes to maintain its existing electric transmission system and to meet regulatory compliance requirements. However, the Commission acknowledged that to the extent that an asset management project will result in a non-incidental, or incremental, increase in transmission capacity, the incremental portion of the asset management project would be subject to the transmission planning requirements of Order No. 890 and would have to be submitted for consideration in CAISO’s TPP. FERC also noted that while the projects and activities at issue in this proceeding are not subject to the transmission planning requirements of Order No. 890, Complainants, other stakeholders, and PG&E are all likely to benefit from increased transparency into asset management projects. FERC strongly encouraged PG&E to continue its efforts to work with Complainants and other stakeholders to develop a process to share and review information with interested parties regarding asset management projects that are not considered through the TPP.
On September 16, 2019, in Docket ER18-169, Southern California Edison (SCE) filed a settlement that it offered to the intervenors that is intended to resolve all issues in this Docket as well as in EL18-44. Below are some of the key provisions:
On September 6, 2019, in Docket No. 19-2769, Exelon, on behalf of PEPCO, requested recovery of 50% of prudently-incurred costs associated with the PEPCO-assigned PJM baseline reliability projects (“Potomac River Project”) that PJM subsequently cancelled, under its Regional Transmission Expansion Plan (“RTEP”) Protocols. Exelon requested recovery over five years of $616,472.36 through PEPCO’s formula rate, which is 50% of the now-abandoned capital costs of the Potomac River Project. PEPCO did not have an abandonment incentive to recover 100% of the cancelled project costs. The rate impacts are minimal. Under the PJM RTEP obligation-to-build requirements, PEPCO commenced construction of the Potomac River Project. However, PJM cancelled the Potomac River Project, which was beyond PEPCO’s control. PEPCO incurred costs consistent with the timetables required for it to satisfy its OATT obligations and directives of PJM. The allocation of the costs of the Potomac River Project is governed by PJM’s OATT as it was in effect at the time that the Potomac River Project was approved, and Exelon is only seeking approval of the recovery of the costs, not the cost allocation, which is outside the scope of this proceeding.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.