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.
Pacific Gas and Electric requests abandonment incentive for work related to two projects awarded to LS Power
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.
On April 1 and 10, 2020 in AC20-81, San Diego Gas and Electric (SDG&E) asked FERC for a waiver related to short-term debt in the AFUDC calculation. SDG&E requested to modify its existing AFUDC rate calculation in response to the Coronavirus (COVID-19) emergency, beginning on March 1, 2020. SDG&E stated that it may significantly increase the amount of short-term debt and cash reserves it carries in response to the COVID-19 emergency. FERC approved the request and told SDG&E that it must disclose its application of this waiver and calculation of AFUDC in its FERC Form No. 1, Annual Report of Major Electric Utilities, Licensees and Others (Form 1).
SDG&E proposed to use a methodology for calculating its AFUDC that will enable it to exclude certain portions of its short-term debt from its AFUDC rate calculation, limited to a specific floor. Specifically, SDG&E proposed to first apply existing waivers previously granted by the Commission to its average short-term debt balances to arrive at a net average short-term debt balance. Next, SDG&E proposed to compare the net average short-term debt balance to an established floor of $15.2 million. If the net average short-term debt balance is less than $15.2 million, SDG&E proposed to include the net average short-term debt balance in the calculation of its AFUDC rate. If the net average short-term debt balance exceeds the $15.2 million floor and SDG&E is also holding cash and cash equivalents equal to or greater than that excess, SDG&E proposed to include the established floor of $15.2 million of short-term debt balance in the calculation of its AFUDC rate.
FERC’s accounting regulations and precedent requires the maximum AFUDC rate to be computed by considering short-term debt as the first source of construction financing. This is based on the premise that short-term debt is not used elsewhere in the development of rates. Historically, the Commission has only provided exceptions to this AFUDC requirement in unique situations where certain amounts of short-term debt were a defined cost in the setting of rates. However, SDG&E’s need to maintain liquidity and protect against financial market uncertainty during this unique state of emergency also warrants exception.
 See Docket Nos. AC16-194-000 (granting SDG&E exclusion from its AFUDC calculation short-term debt used to finance net revenue under-collections recorded in SDG&E’s regulatory balancing and memo accounts); AC15-58-000 (granting SDG&E exclusion for short-term debt associated with the San Onofre Nuclear Generating Station); and AC13-96-000 (granting SDG&E exclusion from its AFUDC calculation short-term debt used to finance nuclear fuel inventors and customer hedging requirements).
 SDG&E represents that it calculated a floor of $15.2 million by taking a three-year average (2017, 2018, and 2019) of the short-term debt included in its AFUDC calculation.
 See Order Adopting Amendment to Uniform System of Accounts for Public Utilities and Licensees and for Natural Gas Companies, Order No. 561, 57 F.P.C. 608 (1977) at p. 1.
The following describes the different types of reliability projects and their cost allocation approach in PJM:
RTEP (Regional Transmission Expansion Plan) Reliability Projects
Description and Cost Allocation
(Reliability Projects are Required Transmission Enhancements that are included in the RTEP to address one or more reliability violations or to address operational adequacy and performance issues)
1. Regional Facilities
Required Transmission Enhancements included in the RTEP that are transmission facilities that: (a) are AC facilities that operate at or above 500 kV; (b) are double-circuit AC facilities that operate at or above 345 kV; (c) are AC or DC shunt reactive resources connected to a facility from (a) or (b); or (d) are DC facilities that meet the necessary PJM.
Costs allocated using a hybrid cost allocation method – 50% allocated on a load-ratio share basis and 50% allocated using solution-based distribution factor (DFAX) method
2. Necessary Lower Voltage Facilities
Required Transmission Enhancements included in the RTEP that are lower voltage facilities that must be constructed or reinforced to support new Regional Facilities.
Costs allocated using a hybrid cost allocation method – 50% allocated on a load-ratio share basis and 50% allocated using solution-based distribution factor (DFAX) method
3. Lower Voltage Facilities
Required Transmission Enhancements that: (a) are not Regional Facilities; and (b) are not “Necessary Lower Voltage Facilities.
100% allocated using solution-based DFAX method
4. Local Planning (Form 715) Facilities
Projects resulting from Annual Transmission Planning and Evaluation Report that any transmitting utility that operates integrated transmission facilities at or above 100 kV must file with the Commission. Form No. 715 requires submission of transmission planning reliability criteria that the transmission owner uses to assess and test the strength and limits of its transmission system.
Allocated as Regional Facilities, Necessary Lower Voltage Facilities or Lower Voltage Facilities, depending into which category the Local Planning Facility fits.
In developing the RTEP, PJM identifies transmission projects to address different criteria, including PJM planning procedures, North American Electric Reliability Corporation (NERC) Reliability Standards, Regional Entity reliability principles and standards, and individual transmission owner Form No. 715 local planning criteria.
 Per Schedule 12 of the PJM OATT
 The Solution-Based DFAX method evaluates the projected relative use on the new Reliability Project by the load in each zone and withdrawals by merchant transmission facilities, and through this power flow analysis, identifies projected benefits for individual entities in relation to power flows.
 Compliance filing pending at FERC in Docket No. ER15-1344.
In January 23, 200 in ER15-1436, FERC determined that Entergy’s proposal to include prepaid and accrued pension costs in its transmission formula rate has not been shown to be just and reasonable. FERC’s finding is without prejudice to Entergy making a future filing that adequately demonstrates that its future proposal, including its methodology for calculating prepaid and accrued pension costs, is just and reasonable.
First, FERC described pension accounting and when it is appropriate to include prepaid pension costs or accrued pension costs in rate base. Prepaid and accrued pension costs can arise when a utility makes contributions to fund a pension trust in order to meet employee pension plan obligations. The costs associated with the pension plans that are reported on the utility’s income statement are referred to as the utility’s “pension expense” or “net periodic pension cost.” Pension expense for a given year includes pension obligations accrued that year, interest, and the return on the assets in the trust (specifically, the components of pension expense are service cost, interest cost, actual return on plan assets, gain or loss, amortization of unrecognized prior service cost, and amortization of the unrecognized net obligation of asset). While pension obligations and interest increase pension expense, the return on the assets in the trust will generally decrease pension expense. A utility generally receives recovery of pension costs based on the amount of pension expense recorded on the books. Accordingly, a prepaid pension cost (an asset) is the amount by which cumulative contributions to a pension trust exceed cumulative pension expense. An accrued pension cost (a liability) is the amount by which cumulative pension expense exceeds cumulative contributions. As a general matter, it is just and reasonable for a utility to include prepaid pension costs in rate base when its pension expense recovered from customers is less than its contributions to fund pension costs (increase to rate base). Likewise, it is just and reasonable for a utility to include accrued pension costs in rate base when it has recovered pension expense from customers in excess of its pension costs (reduction to rate base).
Entergy states that its independent actuary calculates prepaid pension costs by taking the pension plan’s Funded Status (which is Fair Value of Plan Assets minus Projected Benefit Obligation) for the year and then backing out Unrecognized Gains/Losses. This can be reflected in the following formula:
Prepaid or (Accrued) Pension Cost = Fair Value of Plan Assets – Projected Benefit Obligation + Unrecognized Net (Gain) or Loss
FERC found that Entergy had not demonstrated that its proposed formula for calculating prepaid pension costs is just and reasonable. Consistent with the above explanation, the appropriate way to calculate prepaid pension costs includable in rate base would be to calculate the cumulative differences between each year’s pension contributions made by Entergy and pension expenses. Entergy proposes to use a different formula (i.e., Funded Status minus Unrecognized Gains and Losses). Although Entergy asserts that this formula leads to the same result, we find that Entergy has not adequately supported this claim.
Specifically, Entergy’s proposed formula includes components that Entergy has not fully explained and that may not be appropriate to include in the calculation of prepaid pension costs to be included in rate base. For instance, although Entergy argues that it is reasonable to calculate prepaid pension costs by starting with the plan’s Funded Status and backing out Unrecognized Gains/Losses, Entergy does not adequately explain what comprises Unrecognized Gains/Losses or why backing out those amounts to compute prepaid pension costs in rate base yields a just and reasonable result. Without additional explanation, we are unable to evaluate whether Unrecognized Gains/Losses are an appropriate component to include in the calculation of prepaid pension costs to be included in rate base.
Furthermore, Entergy did not explain why using the Funded Status is an appropriate methodology to calculate prepaid pension costs in rate base. Entergy explains that Funded Status equals Fair Value of Plan Assets minus Projected Benefit Obligation, but Entergy does not explain why using Funded Status and Unrecognized Gains/Losses yields the same result as calculating cumulative employer contributions and cumulative pension expense. In some instances, it may be inappropriate to use Funded Status for calculating prepaid pension costs. For example, Entergy’s actuarial disclosure includes a line item for employee contributions for the calculation of Fair Value of Plan Assets, which is a component of Funded Status. However, employee contributions to a pension trust are not shareholder financed funds that the utility has paid out of pocket. Consequently, it would not be just and reasonable for Entergy to include amounts that employees contribute to pension plans in rate base and earn a return on such amounts.
Lastly, FERC found that Entergy’s pension plan funding discretion did not, in and of itself, make Entergy’s proposal unjust and unreasonable. Entergy states that it aims to fully fund its pension plans at the 100 percent level and to not let the funding levels fall below 80 percent. Entergy is not required to provide a policy statement or other documents describing how it exercises its pension funding discretion. As discussed above, while we are rejecting Entergy’s proposal to include a line item for prepaid and accrued pension costs in rate base, we note that, to the extent a utility has a line item for prepaid or accrued pension costs in its transmission formula rate and customers are concerned the utility has funded its pension plans at levels that are not prudent, they may challenge the utility’s pension funding levels when the utility files its annual transmission formula rate updates.
FERC recently issued Opinion 554-A related to the Path (Potomac-Appalachian Transmission Highline, LLC) transmission project, which was cancelled by PJM in 2011. The PATH Project was to be a 275-mile 765 kV line from Amos Substation in West Virginia through Virginia to a new Kemptown Substation in Maryland. In Opinion 554, FERC had found that PATH’s base ROE should be reduced from 10.4% to 8.11% to reflect reduced risks (FERC found that, in the abandonment phase of the PATH Project, PATH's risk profile had decreased significantly as compared to the proxy group companies that face ongoing business risks). Additionally, FERC disallowed certain civic, political and related costs from recovery. PATH requested rehearing of Opinion 554. FERC granted rehearing for the following items:
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.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.