In an Order issued by FERC on January 29, 2019 in ER18-2342, FERC accepted GridLiance Heartland’s proposed formula rate and protocols, including the MISO 10.32% base ROE, a 50 basis point RTO Participation Adder, and the Regulatory Asset and Hypothetical Capital Structure incentives, and granted GridLiance Heartland’s request for authorization to replicate its Formula Rate and incentives granted in this docket for future affiliates formed to operate in MISO. Prior to GridLiance using the formula rate (currently it does not own any transmission assets in MISO), it must submit a filing pursuant to section 205 to include the Formula Rate in the MISO OATT. FERC allowed GridLiance to include an income tax allowance in the proposed Formula Rate, but suspended the issue, subject to refund, and set the matter for hearing and settlement judge procedures. In fact, FERC initiated a Section 206 investigation (EL19-29) on the appropriateness of GridLiance’ s inclusion of an income tax allowance in two other formula rates - GridLiance High Plains and GridLiance West. FERC is concerned that including an income tax allowance in these Formula Rates may cause the same double recovery of income taxes described in United Airlines (DC Court of Appeals) and in FERC’s Revised Policy Statement on income taxes.
Below are items discussed by FERC in the Order that are worthy of individual summary:
1. FERC stated concern over the cost of debt included in the Formula Rate during the period when GridLiance Heartland may acquire construction financing but prior to acquiring any long-term debt. FERC found GridLiance Heartland’s proposal to use a proxy debt rate for the period in which GridLiance Heartland does not hold any debt just and reasonable, but also found that GridLiance Heartland’s Formula Rate should track actual costs to the extent possible. Accordingly, FERC required that GridLiance Heartland revise its Formula Rate to provide for recovery of actual short-term debt from construction financing, as necessary, during the period that GridLiance Heartland acquires construction financing but prior to issuing long-term debt.
2. FERC found GridLiance Heartland’s affiliate cost allocation description acceptable for informational purposes with the understanding that GridLiance Heartland must provide in its annual update and informational filings details describing the affiliate cost allocation used for the applicable rate year and any changes from the previous year, as well as the magnitude of such costs, and that any interested party will have the chance to review the affiliate cost allocation methodology and associated costs during the information exchange and challenge periods. GridLiance Heartland will bear the burden of proof to demonstrate that its affiliate cost allocation methodology and associated costs are just and reasonable.
3. FERC granted GridLiance Heartland’s request for authorization to use a hypothetical capital structure of 60% equity and 40% debt, as well as GridLiance Heartland’s proposal to adopt its actual capital structure, capped at 60% equity, once it has any assets in service. FERC understands that nonincumbent transmission developers have a particular need for the Hypothetical Capital Structure Incentive because it establishes certain financial principles that incumbent transmission owners currently have in place but that remain undetermined for nonincumbent transmission developers and that granting this request furthers the policy goal of facilitating the participation of nonincumbent transmission developers in the Order No. 1000 transmission planning processes, thereby encouraging competition.
4. FERC granted GridLiance Heartland the Regulatory Asset Incentive as nonincumbent transmission developers bidding on regional transmission projects in MISO’s competitive solicitation process must incur early pre-commercial and formation costs, but do not have a mechanism to recover these costs as they are incurred, as do incumbent transmission owners. FERC granted carrying costs, provided they would not result in a higher amount of interest than is allowed for construction expenditures that accrue in Allowance for Funds Used During Construction. FERC stated that GridLiance Heartland must make a section 205 filing to demonstrate that the pre-commercial and formation costs are just and reasonable before it includes them in rates and that GridLiance Heartland must establish that the costs included in the regulatory asset are costs that otherwise would have been chargeable to expense in the period incurred but were deferred consistent with the authorization granted herein.
 In the Policy Statement, FERC found that an impermissible double recovery results from granting a Master Limited Partnership (MLP) natural gas pipeline both an income tax allowance and a return on equity pursuant to the discounted cash flow methodology. FERC stated in the Policy Statement that it would address this issue for non-MLP partnership forms as those issues arise in subsequent proceedings. That is what they are doing here with GridLiance.
Electric Wholesale Power agreements and the impending Pacific Gas and Electric Bankruptcy filing
Pacific Gas and Electric recently announced that it will file for bankruptcy protection due to, among other reasons, liabilities relating to wildfires in California and that it will make that filing on or about January 29, 2019. In order to protect its wholesale power purchase agreements, NextEra requested in EL19-35 that FERC issue an order finding PG&E may not abrogate, amend, or reject its FERC-jurisdictional wholesale power purchase agreements with NextEra in any bankruptcy proceedings that may be initiated by PG&E without first obtaining approval from FERC. In its January 25, 2019 Order, FERC concluded that it and the bankruptcy courts have concurrent jurisdiction to review and address the disposition of wholesale power contracts sought to be rejected through bankruptcy and, therefore, found that, to give effect to both the FPA and the Bankruptcy Code, a party to a Commission-jurisdictional wholesale power purchase agreement must obtain approval from both FERC and the bankruptcy court to modify the filed rate and reject the contract.
Comments filed in ferc rulemaking proceeding on electric transmission rate impacts from tax cut and job act
Following is a summary of recent comments provided to FERC in its Notice of Proposed Rulemaking on the impacts to electric transmission rates from the Tax Cut and Jobs Act (TCJA) (RM19-5). The comments are limited since FERC previously addressed the rate impacts of the TCJA in its Notice of Inquiry earlier in 2018 where it received extensive comments. I expect FERC will issues the final rule within two months. Compliance filings from all transmission owners with formula rates, who have not already addressed the TCJA impacts, will be due within 90 days of the final rule. This summary is organized alphabetically by those commenting.
American Municipal Power (AMP) requests that FERC: 1) provide further guidance on rate base neutrality to avoid accepting solutions that erode transparency in transmission formula rates; 2) require TOs to include the amortization of excess and deficient ADIT within the same portion of the formula rate calculation that is currently used to determine income tax expense and the associated tax gross up as this will promote transparency and provide a means to address future changes in federal, state or local income taxes; 3) TOs with transmission formula rates as well as stated rates should include a new worksheet to track information related to excess and deficient ADIT, including information necessary as a TOs excess and deficient ADIT will include a mix of balances that are protected and unprotected and the classification of these balances requires an item-by-item inquiry; 4) require the return of any incremental charges collected after December 31, 2017 that relate to utilizing the pre-TCJA tax rate; and 5) though AMP agrees with the 90-day compliance filing requirement, FERC should take immediate action to address TOs rates that are currently based on the 35% federal income tax rate.
American Public Power (APPA) agrees with FERC’s proposal not to adopt a generic amortization period for unprotected excess or deficient ADIT under formula and stated rates if FERC makes clear that it will scrutinize proposals to adopt lengthy amortization periods for excess unprotected ADIT. APPA recommends the following: 1) where the full amount of TCJA-related excess ADIT for a TO with a stated rate is greater than the amount of excess ADIT calculated based on the ADIT in the utility’s last rate case, the full amount of excess ADIT ultimately must be returned to customers; 2) TOs with stated rates should provide information on actual, current excess or deficient ADIT as well as the that based on the ADIT in the last rate case; 3) not authorize recovery of past period deficient ADIT for which recovery should have been sought earlier under the requirements of Order No. 144; 4) customers should receive the full amount of any excess ADIT balance associated with the TCJA, even though the effective date of new rates may be after January 1, 2018; 5) future proposals to return or recover excess or deficient ADIT will require submission of a FPA section 205 filing, and transmission formula rates should be required to specify this filing requirement; and 6) formula rate compliance filings should include ADIT accounting information, as well as populated formulas showing the operation and effect of the proposed formula rate mechanisms, to allow interested parties to evaluate the effects of the proposed formula rate changes.
Avista states FERC, in its Show Cause Order process, found that Avista need not propose revisions to its stated transmission rates to reflect the recent change in the federal corporate income tax rate. Therefore, FERC should clarify that, where, as with Avista, it has already determined that no revision to stated transmission rates is necessary, a compliance filing is not required and that the treatment of excess or deficient ADIT should be addressed in the TOs next rate case to establish stated transmission rates.
Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California (Six Cities) request that FERC require the following: 1) where a utility with a stated rate has ADIT that is greater than the amount of excess ADIT calculated in its last rate case, the full amount of excess ADIT must be flowed back to customers; 2) public utilities with stated rates should provide information on actual, current excess ADIT and a calculation of excess or deficient ADIT based on the ADIT in the utility’s last rate case; 3) customers should receive the full amount of any excess ADIT resulting from the Tax Act dating back to January 1, 2018, despite any later effective date for new rates; and 4) utilities with rates subject to moratoria should be required to defer amortization of excess ADIT and flow back the full amount, coinciding with the close of the moratorium. Six Cities also states that FERC should require even greater transparency and consistency among public utilities and ensure that utilities with stated rates are required to provide the same level of transparency as utilities with formula rates. To that end, the Commission should: (1) adopt a pro forma worksheet; (2) require additional detail be provided by public utilities; and (3) require all utilities, including those with stated rates, to use the pro forma worksheet to reflect the calculation and amortization of excess and deficient ADIT. Six Cities proposes that the following additional detail be included in the required worksheet: 1) the pro forma worksheet should itemize the unprotected and protected excess and deficient ADIT amounts into more granular categories: i) protected property-related excess and deficient ADIT should be categorized as: (a) Property-Related – Accelerated Tax Depreciation; (b) Net Operating Loss – Related to Accelerated Depreciation; (c) Repairs Deduction – Related to Accelerated Depreciation; (d) Contributions in Aid of Construction – (CIAC); and (e) Cost of Removal; ii) unprotected property-related excess and deficient ADIT should be categorized as: (a) Basis Adjustments – Not Related to Accelerated Depreciation, by individual basis adjustment; (b) NOL – Not Related to Accelerated Depreciation; and (c) Cost of Removal – Not a Component of a Depreciation Rate and not based on a Net Salvage Value; and iii) unprotected non-property related excess and deficient ADIT should be categorized based on whether it is attributable to vacation pay, repairs, pensions, accrued payroll, property tax, capitalized interest, etc.; 2) all specific ADIT items should be listed in the required worksheet - there are certain items, like equity Allowance for Funds Used During Construction (“AFUDC”) that should not be recovered through rates, rendering it inappropriate to recover ADIT related to these items through rates, unless the TO had previously received authorization from FERC to recover them; 3) TOs should be required to specify those items that are either below-the-line or specifically inapplicable to customers and, therefore, are not included in rates; and 4) the worksheet should specify those amounts that are inapplicable to customers, such as ADIT amounts for items such as merger costs due to a hold harmless agreement; FASB 109 ADIT items that are excluded from rates; 5) FASB 106 ADIT items that are excluded from rates; regulatory assets and liabilities that have not been approved to be included in customer rates; and 6) any ADIT items specifically related to transmission, but allocated to other functions such as Gas, Production, Retail, etc.
Delaware Municipal Electric Coop recommends 1) TOs follow the Uniform System of Accounts (“USoA”) and FERC precedent, including with respect to the requirement that TOs must submit section 205 filings reflecting in rates any regulatory assets or liabilities arising from future tax changes, or other types of deferred taxes that are recorded as regulatory assets and which have not been previously approved; 2) TOs with transmission formula rates be directed to provide transparency associated with the regulatory liabilities and assets by booking the excess or deficient ADIT amounts to separate accounts or subaccounts and to provide greater detail in associated formula rate line items and worksheets; 3) describing the correct approach for computing excess or deficient ADIT; 4) customers receive the excess ADIT without unreasonable delay; 5) TOs to include in their worksheets a detailed computation of the excess or deficient ADIT; 6) that, irrespective of the test period used, FERC should ensure that all the TCJA benefits, including the use of the 21% income tax rate, become effective as of January 1, 2018, and that all customer refunds be made with interest; and 7) there are additional TCJA provisions, not discussed in the NOPR, that affect TOs rates, particularly, tax deductions that have been affected by the TCJA as well as the effect of the TCJA on Bonus Depreciation, Net Operating Losses, among other affected areas.
Edison Electric Institute (EEI) (comments supported by Duke, First Energy and Avista) seeks clarification on several items: 1) FERC should allow a case-by-case approach for determining amortization of unprotected ADIT as the amortization period depends on the specific facts and circumstances for each TO and due to the diversity of assets that could underlie unprotected ADIT balances, including state income taxes, employee benefits, repairs, etc.; 2) the annual information presented in Form 1, in conjunction with the support provided in the annual updates, provides the necessary transparency and therefore a new worksheet is unnecessary; 3) compliance filings for formula rates should be due the later of 90 days from issuance of a final rule (as FERC proposed) or at the time of the TOs next informational or true-up filing; 4) TOs with stated rates should have the opportunity to show that their rates are not unjust and unreasonable even after the return of excess ADIT, should not be required to produce a compliance filing if they include the required information in their Form 1, and should be allowed to do single-issue ratemaking to address issues from the TCJA; 5) TOs transitioning from stated to formula rates should be allowed to address all issues related to the potential effects of the TCJA on ADIT balances in the context of the proceeding to transition from stated to formula rates; and 6) FERC should clarify whether the Policy Statement (accounting items related to the TCJA) applies in the case of all ordinary retirements or whether the Policy Statement excludes all ordinary retirements, and whether the Policy Statement applies to all retirements and sales that are closed after November 23, 2018, the Policy Statement’s effective date.
Electricity Consumers Resource Council (“ELCON”), the American Forest & Paper Association (“AF&PA”), and the American Chemistry Council (“ACC”) request that FERC promptly issue the final rule, which already is delayed, and take whatever further actions are needed for full and timely return of customer monies, including interest charges to account for the delays that already have occurred, and to establish an incentive against further delays.
Eversource supports FERC proposals with some clarifications and comments: 1) FERC to make clear that it will permit TOs to propose a mechanism in their formula rates to adjust for excess or deficient ADIT that arises due to future changes in the federal and state income tax rates; 2) supports FERC’s not prescribing a specific method to flow back or recover the excess or deficient ADIT amounts from customers; 3) supports FERC’s proposal to allow for a case-by-case approach with respect to the amortization period for excess or deficient unprotected ADIT and recommends that non-protected ADIT be amortized based on an approximate average life of the assets that gave rise to the ADIT balances; and 4) the proposed ADIT worksheet may be redundant in light of the requirements for disclosure in Form 1 as the categories of ADIT-related information appear to be essentially the same information in both the worksheet and in Form 1.
MISO Transmission Owners (MISO TOs) state that their formula rates already ensure rate base neutrality and provides or will soon provide for amortization of excess and deficient ADIT, so no further adjustments for these items are needed. The MISO TOs request that FERC find that a life of the asset approach (i.e., ARAM or RSGM) is per se just and reasonable in amortizing unprotected ADIT as this approach would not prohibit a TO from using a shorter flow-back period. FERC should clarify that the requirements for TOs with transmission stated rates do not apply to TOs with transmission formula rates that have other stated rates in their OATTs, such as reactive power rates. The MISO TOs agree that it is necessary to provide interested parties adequate transparency but disagree that requiring a permanent ADIT work paper into their formula rate templates is the most efficient or effective means of accomplishing this objective. Creating an ADIT work paper that both contains all the information FERC proposes and accommodates the unique circumstances of each TO will be an extremely time-consuming and tedious process. Rather than mandating the permanent ADIT work paper, FERC should rely upon the existing formula rate protocol processes.
National Rural Electric Coop (NREC) supports FERC’s proposal with the understanding NREC may request further clarifications or request additional measures in the future.
Public Service Electric and Gas recommends that FERC not require TOs with formula rates to incorporate a new permanent worksheet into their annual transmission formula rate filings as such worksheet is unnecessary and burdensome since existing FERC practice already provides that sufficient information regarding ADIT balances be made available to interested third parties, the information is included in FERC Form No. 1 and supporting workpapers and the 2014 Staff Guidance regarding formula rate updates provides that annual update filings shall include support for all inputs.
Transmission Access Policy Study Group (TAPS), an association of transmission-dependent utilities in more than 35 states, requested that FERC explicitly require that a TOs changes to its formula rates related to excess and deficient ADIT be filed pursuant to FPA section 205 to obtain FERC approval prior to including in rates the amortization of excess or deficient ADIT following a tax change.
Xcel Energy requests that FERC provide the flexibility for TOs to address excess and deficient ADIT with stakeholders through settlement processes and that the final rule would not overrule such settlements already effective. One Xcel company has a settlement that provides that excess and deficient ADIT balances begin to be flowed back to customers effective January 1, 2018, the effective date of the Tax Cut and Job Act (TCJA). The settlement provides that excess plant-related, protected ADIT balances, including excess ADIT related to net operating losses, and excess plant-related unprotected ADIT balances will be amortized for accounting purposes and will be flowed back in rates based on the Average Rate Assumption Method (“ARAM”); and excess non-plant unprotected ADIT balances will be amortized for accounting purposes and flowed back in rates over five years. For the Xcel company, the underlying assets and liabilities that gave rise to the non-plant unprotected ADIT have varying lives, and the five-year amortization period considers both the varying lives and inter-generational equity issues. Xcel further believes that excess and deficient ADIT should be amortized in a consistent manner across a TOs various rate jurisdictions (multiple states, FERC), if possible.
LS Power has requested an abandonment incentive for the AC Transmission Upgrades in New York (the Project). The AC Transmission Upgrades are in the final stage of consideration by the NYISO under NYISO’s Order No. 1000 competitive process for Public Policy Transmission Planning and LS Power expects to be awarded at least one of the two segments of the Project. NYISO estimates that both segments of the Project will have a total capital cost of $1.1 to $1.2 billion (including a 30% contingency, but not including the cost of certain required upgrades). The Project has an anticipated in-service date of December 2023. The NYISO Board is expected to award the Project in March 2019, at which time construction expenditures will increase substantially. LS Power expects to request other transmission incentives, for example a hypothetical capital structure during construction, later. The Project meets the rebuttable presumption of Order 679 in that the Project was considered through the Public Policy Planning process of the NYISO and needs siting approval from the New York Public Service Commission (NYPSC). As described below, the Project faces significant regulatory, permitting, and other requirements that may result in the Project being terminated at no fault of LSPG-NY and New York Power Authority (NYPA). As a result, approval of Abandonment Recovery is warranted.
A NYISO Draft Report in mid-2018 recommended selection of a joint proposal from Joint LS Power and the NYPA for both Segment A and Segment B. The NYISO Board considered and reviewed the Draft Report over several meetings from July to December. On December 27, 2018, NYISO posted the AC Transmission Public Policy Transmission Planning Report Addendum (“Report Addendum”). The Report Addendum will be the subject of additional stakeholder review and comment, and the Board is expected to consider the Draft Report and Report Addendum as its March board meeting, with final approval of the AC Transmission Upgrades. The Report Addendum continues to recommend selection of a joint proposal from LS Power and NYPA for Segment A, but recommends a New York Transco proposal for Segment B.
There are substantial risks associated with the Project. Construction of the Project will require numerous permits and approvals at each of the federal, state, and local government levels. The Project is expected to pass through portions of eight different counties and over two dozen townships. There already has been thousands of public comments in the multi-year NYPSC process that proceeded the NYISO process. Significant additional public consultation will be required in the permitting process for
the Project, in order to obtain a Certificate of Environmental Capability and Public Need (CECPN) from the NYPSC under Article VII of the Public Service Law. This permitting process will provide an opportunity for many constituencies to raise issues and concerns regarding the impacts of the transmission line construction and operation within their communities. This includes participation from the New York Department of Agriculture and Markets, which protects the interests of agricultural resources, a party by statute to transmission line permitting in New York. The New York Department of Conservation will participate, and many provisions will be required to minimize impacts on sensitive species, such as the endangered Indiana bat, which will require seasonal limitations on construction activities. The CECPN requires a showing to be made for Project need. Since the Project is not strictly needed for reliability, there could be challenges to the need for the Project. There has already been significant public comment related to the AC Transmission Public Policy Needs, with over 3,000 public comments received to date, largely in opposition to aspects of the AC Transmission process including the need for new or upgraded transmission lines. Local regulations and the compatibility of the Project with local plans is another area that is required to be described in the Article VII application and considered in the Article VII process. There has already been significant participation in the NYPSC process by many local towns in the project area.
LS Power: Through various subsidiaries, LS Power develops, owns, and operates electric transmission and independent power projects throughout the United States. LS Power subsidiaries have the following transmission projects in operations, under construction or in advanced development: (1) the ON Line transmission project, a 231-mile, 500 kV transmission project in service in Nevada (co-owned with Nevada Power Company); (2) the Harry Allen to Eldorado 500 kV Transmission Project (selected through a competitive process by the California Independent System Operator), which will connect with the southern terminus of the ON Line transmission project; (3) an approximately 300 mile high-voltage transmission system in service in Texas; (4) the new Silver Run 230 kV substation in Delaware and a new 230 kV line connecting the Silver Run substation to an existing substation in New Jersey (selected through a competitive process by PJM Interconnection, L.L.C.); and (5) Duff to Coleman 345 kV transmission line, located primarily in Indiana with a portion in Kentucky (selected through a
competitive process by the Midcontinent Independent System Operator, Inc.).
On November 16, 2018, American Transmission Company LLC (ATC) (ER19-360) and ITC Midwest (ITC) (ER19-355) both requested from FERC, effective January 16, 2019, incentive rate treatment to recover 100 percent of all prudently-incurred costs associated with its investment in the Cardinal-Hickory Creek 345 kV Project (Project) if the Project is abandoned or cancelled for reasons beyond ATC’s control (Abandoned Plant Incentive). The Project is a MISO Multi-Value Project that will consist of approximately 102 to 120 miles of new 345 kV transmission line from Dane County, Wisconsin to Dubuque County, Iowa, with associated substation expansions. ATC and ITC Midwest LLC (ITC Midwest) each owns 45.5% of the Project, and Dairyland Power Cooperative (Dairyland) owns the remaining nine percent. ATC states that the Project is estimated to cost between $492 million and $543 million, depending on the route, and that the transmission line is expected to be in service in December 2023. FERC granted both ATC’s and ITC’s request as meeting the requirements of Order 679, namely that an applicant must show that the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion. FERC previously established the process for an applicant to demonstrate that it meets this standard, including a rebuttable presumption that the standard is met if: 1) the transmission project results from a fair and open regional planning process that considers and evaluates the project for reliability or congestion and is found to be acceptable to the Commission; or 2) a project has received construction approval from an appropriate state commission or state siting authority. FERC found that since the project was reviewed and approved in the MISO planning process, it met the rebuttable presumption. It also found that the incentive request was tailored to address the demonstrable risks or challenges faced by each applicant. These risks are federal (U.S. Fish and Wildlife Service and the Army Corps of Engineers), state (Wisconsin and Iowa), and local approvals, along with the easement acquisition process which could be contentious and result in delays or increased costs (the Project must also cross the Mississippi River as well as federal wildlife refuge lands), and in order to keep the Project on schedule toward its December 2023 in-service date, capital investments must be made before the ongoing, overlapping regulatory processes and easement acquisitions are complete.
This summary covers the abandoned plant costs for the Potomac-Appalachian Transmission Highline, LLC (PATH) transmission project which was cancelled by PJM in 2011. It is an example of the process at FERC to receive recovery of abandoned plant costs after a project is cancelled even with the abandonment incentive.
PATH is a subsidiary of American Electric Power and FirstEnergy (the Parent Companies). PATH has two revenue requirements that are the subject of compliance at FERC - one for PATH West Virginia Transmission Company, L.L.C. (jointly-owned by the Parent Companies), and one for PATH Allegheny Transmission Company, LLC (owned solely FirstEnergy). FERC granted PATH an abandonment incentive. After authorizing the Project, PJM later determined that it no longer required the Project and cancelled it. In September 2012, PATH filed to recover the net amount of approximately $121.5 million in abandonment costs it incurred between January 1, 2008 and August 31, 2012, proposing to subtract revenues from the closing out of future transactions (such as land sales) through PATH’s formula rates. FERC set the proceeding for hearing, which was ultimately consolidated with two other Formal Challenge Proceedings concerning PATH.
In January 2017, FERC issued Opinion No. 554 where it ordered compliance on several matters, including: (1) PATH’s civic and political costs at issue in the Formal Challenge Proceedings; (2) advertising costs also at issue in the Formal Challenge Proceedings; (3) losses on the sale of real estate purchased for the Project; (5) the allowed return; and (6) the appropriate amortization period for the abandoned plant costs. In Opinion No. 554, FERC disallowed some of the expenses at issue in the Formal Challenge Proceedings. PATH had flowed a portion of these amounts into the abandonment costs for which PATH sought recovery. Opinion No. 554 disallowed that portion of abandonment costs related to the costs at issue in the Formal Challenge. Opinion No. 554 also reduced PATH’s return on equity from 10.4% 8.11%.
In Opinion 554, FERC found that PATH had improperly accounted for numerous costs related to civic and political activities by including the amounts in FERC Accounts that were in PATH’s Formula Rate. FERC found that PATH should have recorded these costs in below the line accounts which PATH’s Formula Rate excludes: Account 426.4 (Expenditures for certain civic, political and related activities) or Account 426.5 (Other Deductions). FERC also found that PATH’s Formula Rate limits PATH’s recovery of Account 930.1 (General Advertising) costs to only those that are Safety Related Advertising, Education and Outreach Cost Support. FERC disallowed costs from rates where PATH had failed its burden of proving that these amounts should neither have been recorded to Account 426.4, nor should they have been considered an includable Safety Related Advertising, Education and Outreach Cost Support expense in PATH’s Formula Rates. FERC found that PATH had joined and supported approximately 80 community and professional organizations, recorded the related expenses to Account 930.2 (Miscellaneous General Expenses), which should have instead been recorded to Account 426.5 (Other Deductions) and excluded from its rates.
In its recent Order dated January 17, 2019 in ER09-1256 and ER12-2708, FERC found that PATH has complied with Opinion No. 554 with respect to some amounts capitalized to plant accounts and reclassified to Account 426.4, but not with respect to advertising expenses. For Account 930.1, General Advertising, FERC directed PATH either to Account 426.4, or to the portion of Account 930.1 that PATH’s formula rate excludes. FERC found discrepancies between the General Advertising amounts reclassified by PATH in its Compliance Filings compared to the General Advertising amounts FERC required PATH to reclassify in Opinion No. 554. FERC ordered that PATH must eliminate all General Advertising costs from its recoverable amounts, or else specifically justify each item considering Opinion No. 554. In making the compliance filing, PATH must provide the journal entries to reflect the adjustments, and workpapers necessary to explain the accounting corrections for that FERC Form No. 1 input that references back to the journal entries; and the revised/corrected draft Form No. 1 inputs.
As to land transactions, FERC found that, for the land sales that PATH made prior to the issuance of Opinion No. 554, PATH complied with the land transaction directives by providing a property-by-property breakdown of the losses that it passed through rates for its past real estate purchases and sales, with separate line items for associated taxes, labor, and other costs, noting a loss of $4,149,091, including various costs associated with the sales, such as taxes and title charges. However, FERC found that PATH has not complied with the directives regarding land transactions for the eight properties it sold after the issuance of Opinion No. 554. For these properties, PATH failed to provide documentation to support its claim and failed to provide any supporting documentation regarding affiliate transactions in any of its filings. As required by Opinion No. 554, PATH failed to provide a property-by-property breakdown of the losses that it has passed through and failed to provide evidence that properties were sold on the open market, or to otherwise establish the asset’s fair market value.
For the eight properties at issue, PATH must demonstrate and provide on compliance: 1) date of sale/transfer; 2) the names of the buyers and sellers and their relationship to PATH affiliates and their parent companies; 3) sale/transfer price for each property; 4) a breakdown of associated expenses (such as taxes or labor); 5) either (i) proof that the property was advertised and sold on the open market with arm’s length bargaining, or (ii) for any transaction not at arm’s length, a detailed narrative showing whether the transaction nevertheless meets the standards laid out in Opinion No. 554; and 6) calculation of the real estate losses that it has passed through and/or proposes to pass through to customers. To the extent that PATH cannot provide evidence that it has disposed of the properties listed in the order, PATH must return to customers the original purchase price of the property plus the associated return on equity that it has received since December 2012. FERC directed PATH to submit the required compliance filing within 30 days and the required refund report within 60 days of the order.
Additionally, FERC order PATH to submit a compliance filing with the Commission describing either: (1) its plan for ending its operations and a timeline for when it intends to file a notice of cancellation of its transmission formula rates, or (2) the type of “transmission or sale of electric energy” that requires its rates to stay in effect (the cancelled project is PATH’s only project).
 For affiliate transfers which were not at arm’s length, the Commission directed PATH to demonstrate that: (1) a competitive solicitation process was designed and implemented without undue preference for an affiliate; (2) the analysis of bids did not favor affiliates, particularly with respect to non-price factors; and (3) the affiliate was selected based on some reasonable combination of price and non-price factors.
On January 16, 2019, FERC initiated rate cases for three natural gas pipeline entities - Bear Creek Storage Company (RP19-51-000), Northern Natural Gas Company (RP19-59-000) and Panhandle Eastern Pipe Line Company, LP (RP19-78-000). FERC’s action stems from Order No. 849 (July 2018) which required each interstate natural gas pipeline to file a one-time report, called FERC Form No. 501-G, that called for a rough estimate of its return on equity before and after the passage of the Tax Cuts & Jobs Act of 2017 and changes to the Commission’s income tax allowance policies for Master Limited Partnerships in response to rulings by the D.C. Circuit. For these three pipeline entities, after review of the respective filings, FERC is concerned that the level of earnings for each company may exceed their actual costs of service, including a reasonable rate of return on equity. The investigations and hearings will determine whether the existing rates are just and reasonable in accordance with section 5 of the Natural Gas Act (NGA). FERC directed each pipeline to file a cost and revenue study for the latest available 12-month period (test period) within 75 days of the issuance of its order. They permitted the natural gas pipeline entities to include a six-month projected analysis of changes to the test period. For more information, click on the following link:
New england roe update
This a summary of briefs filed in the return on equity cases at FERC involving the New England Transmission Owners. This now reflects all briefs.
Currently there are four pending complaints against the New England Transmission Owner’s (NETOs) ROE that go back to 2011. Each complaint has been fully litigated before an Administrative Law Judge (ALJ) with only the first complaint resulting in a FERC Commission decision (Opinion 531). The D.C. Circuit of Appeals vacated the Commission’s determinations in its order on the First Complaint (Opinion No. 531). In the meantime, the NETOs are continuing to collect their 10.57% base ROE from Opinion 531, although the Commission has indicated that it will exercise its “broad remedial authority” to correct its legal error to make whatever ROE it sets on remand effective as of the date of that Order.
On October 16, 2018, FERC issued an order in these complaint cases. In its Order, FERC set forth its methodology for addressing ROE complaints while considering the remand from the DC Court. In its proposal, FERC gives equal weight to the results of the four financial models in the record in the NETO cases, instead of primarily relying on the DCF model. In relying on a broader range of record evidence to estimate the NETOs’ cost of equity, FERC states that this will ensure that the selected ROE is based on substantial evidence and bring its methodology into closer alignment with how investors make investment decisions.
To determine whether an existing ROE remains just and reasonable (i.e., the first prong of the FPA section 206 analysis), FERC proposes (1) relying on the three financial models that produce zones of reasonableness—the DCF, CAPM, and Expected Earnings models—to establish a composite zone of reasonableness; and (2) relying on that composite zone of reasonableness as an evidentiary tool to identify a range of presumptively just and reasonable ROEs for utilities with a similar risk profile to the targeted utility. Under this approach, FERC intends to dismiss an ROE complaint if the targeted utility’s existing ROE falls within the range of presumptively just and reasonable ROEs for a utility of its risk profile—unless that presumption is sufficiently rebutted.
Where the existing ROE has been shown to be unjust and unreasonable and therefore, requiring that FERC move to the second prong of the FPA section 206 analysis, FERC proposes to rely on all four financial models in the record—i.e., the three listed above, plus the Expected Earnings model—to produce four separate cost of equity estimates. FERC proposes to give them equal weight by averaging the four estimates to produce the just and reasonable ROE. For each of the DCF, CAPM, and Expected Earnings models, FERC proposes to use the central tendency of the respective zones of reasonableness as the cost of equity estimate for average risk utilities. FERC would then average those three midpoint/median figures with the sole numerical figure produced by the Risk Premium model to determine the ROE of average risk utilities. FERC would use the midpoint/medians of the resulting lower and upper halves of the zone of reasonableness to determine ROEs for below or above average risk utilities, respectively. Because its current policy is to cap a utility’s total ROE (the base ROE plus incentive ROE adders) at the top of the zone of reasonableness, FERC proposes to use the composite zone of reasonableness produced by the DCF, CAPM, and Expected Earnings to establish the cap on a utility’s total ROE.
The October 16 Order evaluated the justness and reasonableness of existing ROE of the NETOs by dividing a “composite zone of reasonableness” bounded by the average of the highest values obtained in the DCF, CAPM and Expected Earnings analysis, and the average of the three lowest values obtained in those analyses, into quartiles. The Order compares the pre-complaint NETO ROE of 11.14% to a “middle quartile” extending from 37.5% (three-eighths) to 62.5% (five-eighths) of a range from 7.51% to 13.08%, or from 9.6% to 10.99%. Since the NETOs’ Opinion No. 489 ROE of 11.14% exceeds 10.99%, FERC would find it unjust and unreasonable, and reduce it to 10.41%. FERC would also set the total ROE cap at 13.08%.
NETOs support the overall approach proposed by FERC in the October 2018 Order and recommend limited changes to ensure that it is statutorily and procedurally sound and consistent with the D.C. Circuit’s opinion in Emera Maine. The NETOs request that the Commission adopt the following results for these proceedings:
Case Prior ROE Presumptive Range ZOR New ROR
I 11.14% 9.60%-10.99% 7.51%-13.08% 10.41%
II 10.41% 9.85%-11.21% Dismiss - N/A N/A
III 10.41% 9.62%-11.10% Dismiss - N/A N/A
IV 10.41% 9.42%-10.88% Dismiss - N/A N/A
With some limited modifications, FERC’s approach satisfies the two steps of FPA Section 206 and the two holdings of the Court’s Emera Maine decision. First, it accords utilities the “statutory protection” that the Court mandated by ensuring that the Commission will not exercise its FPA Section 206 authority unless it satisfies the “condition precedent” of showing that the existing rate is outside “a broad range of potentially lawful ROEs.” Second, it provides the rational connection between the “record evidence” that undermined the reliability of the DCF analysis and the Commission’s “placement of the base ROE.” In developing a new framework that addresses the Court’s directives, FERC also achieves the “careful balance that attracts sufficient transmission investment but doesn’t impose undue burdens on consumers.”
The NETOs request the following clarifications:
Trial Staff Brief:
Recommends the following:
Complaint Base ROE With Expected Earnings ROE Cap With Expected Earnings
I 9.29% 9.57% 10.82% 11.72%
II 9.26% 9.68% 10.13% 11.62%
III 9.14% 9.58% 11.06% 12.02%
IV 8.45% 9.28% 10.46% 11.63%
Eastern Massachusetts Consumer-Owned entities (EMCOs) state that the DCF remains a sound and reliable method to determine the market cost of equity. FERC has not used other ROE methodologies to same degree as DCF, so other methodologies lack maturity in application by FERC. FERC must exercise extreme caution when employing CAPM and Risk Premium. FERC should not use Expected Earnings as it is based upon accounting data and not reflective of the market cost of equity. FERC’s proposed Expected Earnings analysis is impervious to the market cost of equity capital and heavily anchors ROE results in past regulatory decisions. The proposed averaging of extreme ends of ranges of implied costs of equity exaggerates the skew that results from reliance on the midpoint, as opposed to the median. The results of the NETOs’ non-DCF analyses are substantially overstated in ways that the limited adjustments undertaken in developing the October 16 Order do not address. Failure to deploy a predictable and statistically effective screen for high-end outliers means that the resulting ranges continue to be skewed toward higher than reasonable results.
Recommend that FERC:
Consumer Aligned Parties (CAPS) state that FERC’s proposal to determine a zone of presumptively just and reasonable ROEs that would be used to determine if the existing ROE is just and reasonable is: 1) inconsistent with the Federal Power Act’s consumer protection purpose; 2) creates an asymmetry between Section 205 and 206 cases in that a TO can request a higher ROE if its calculations demonstrate one higher than the existing ROE – on the contrary, in a Section 206 case, the complainant would have to show that the calculated ROE is below the presumptive range; 3) the DC Court did not contemplate, let alone require, a presumption that an above-cost ROE remains just and reasonable unless it exceeds the cost-based level by more than one-eighth of the composite range; 4) the specifics of the proposed presumptive range are arbitrary - the composite range is arbitrary, and the non-DCF methods used in identifying the composite range are unreasonable, if applied as the Order does; and 5) the presumption range departs without justification from precedent specific to New England transmission ROEs in Opinion 489 where FERC required refunds for any NETO which had an ROE different than the new, determined ROE.
CAPS disagree with FERC that the outcome of the prior complaint being deemed the “existing” rate for purposes of the next complaint. CAPs state that the existing ROE for purposes of the second, third, and fourth complaints must be the ROE that is charged or collected by the NETOs—that is, the allowed ROE that was either (a) actually charged when a Section 206 complaint is filed, or (b) determined and fixed by a FERC order making it effective at such time. FERC’s approach here ignores the extended timeline associated with the complaints in these proceedings, where the period between filing of the complaint and Commission action has well exceeded the fifteen-month refund protection afforded by Section 206 and the existing rate will not always be identical to the outcome of the prior Complaint.
CAPs recommend the following changes:
Start End Recommendation Alternative
10/1/2011 12/26/2012 8.91% 9.64%
12/27/2012 12/31/2012 8.79% 9.64%
1/1/2013 3/27/2014 8.79% 9.79%
3/28/2014 7/30/2014 11.14% 11.14%
7/31/2014 10/15/2014 8.64% 9.64%
10/16/2014 10/30/2015 8.64% 9.64%
10/31/2015 4/28/2016 8.91% 9.64%
4/29/2016 9/29/2016 8.33% 9.19%
9/30/2016 7/28/2017 8.64% 9.64%
7/29/2017 9/29/2018 8.91% 9.64%
9/30/2018 continuing 8.33% 9.19%
AEP and EEI Comments:
Both entities request that FERC not decide how to determine the central tendency (midpoint versus median) for a single transmission owner in the NETO proceeding which involves several New England transmission owners.
Southern California Edison Comments:
Suggests that the issue of central tendency for a single-filing utility rate be left for a single utility ROE case where it can be briefed more thoroughly (same point as AEP and EEI) and that FERC consider modifying its proxy group selection criteria to ensure that a small proxy group does not negatively impact ROEs by allowing individual transmission owners who have small proxy groups to propose alternative methods for determining an appropriate proxy group. The practice of setting the low-end threshold 100 basis points above the utility bond yield does not contemplate that the spread between utility bond yields and the cost of utility equity can change over time, and thus the 100-basis point
spread may be too low.
Louisiana Public Service Commission Comments:
Requests late-intervention as they are concerned that they will not have the ability to influence FERC’s direction on ROE in other proceedings involving transmission owners doing business in Louisiana and therefore request that ability here.
 Each of these three methodologies relies on a proxy group to determine a zone of reasonableness, and thus the top and bottom of the zone of reasonableness produced by each methodology can be averaged to determine a single composite zone of reasonableness. After determining the composite zone of reasonableness, FERC will then calculate the lower, middle and upper ranges of that composite zone. The presumptively just and reasonable ROEs for below-average, average, and above-average risk utilities will then be the quartile of the respective zone.
 FERC Trial Staff concludes in Complaint I that the existing 11.14% ROE is unjust and unreasonable and therefore FERC needs to determine the just and reasonable ROE, and they recommend 9.29%. They do not reach such conclusions in the other complaints. They simply provide the information needed for FERC to determine if the existing ROE is within the presumptive just and reasonable range and provide a new ROE if FERC determines that the existing ROE is unjust and unreasonable. Table B provided herein contains Staff’s recommendations if FERC were to reset the ROE and ROE Cap in each complaint case.
In late 2018, Next Era’s affiliate. NEET Midwest, won a competitive solicitation in MISO for the so-called Hartburg-Sabine Project, a $114.8 million Market Efficiency Project identified through MISO’s 2017 comprehensive transmission planning process to relieve congestion in East Texas. In its Selection Report, MISO determined that NEET Midwest’s proposal “offers an outstanding combination of low cost and high value, with best-in class cost and design, best-in-class project implementation plans, and top-tier plans for operations and maintenance,” and will “convey substantial benefits to ratepayers over time.” As highlighted in the Selection Report, NEET Midwest’s “multiple categories of cost caps and cost containment measures increase cost certainty and convey substantial benefits to ratepayers over time.” Here are the cost containment measures that NEET Midwest included in their proposal:
In addition, in Docket ER16- 2717, NEET requested from FERC and received authorization for 1) a Formula Rate for its transmission investments in MISO that is incorporated into the MISO Tariff, 2) a 50 basis point return on equity (“ROE”) adder for Independent System Operator participation (“ISO Participation Adder”); 3) a regulatory asset for NEET Midwest’s prudently incurred pre-commercial and formation costs for later recovery, with carrying charges (“Regulatory Asset Incentive”); and 4) a hypothetical capital structure of 60% equity and 40% debt, to remain in effect until the first transmission project is placed in service (“Hypothetical Capital Structure Incentive”). Any incentive that FERC granted would be subservient to the terms of NEET Midwest’s Proposal for the Hartburg/Sabine Project described above.
On January 4, 2019, NEET Midwest requested the abandonment incentive for this project. This request is pending before FERC in ER19-775.
Republic Transmission, which is owned by LSP Power and Hoosier Energy Rural Electric Cooperative, filed a formula rate at FERC in ER 19-605. Republic Transmission was selected in a MISO competitive process to build a new 345 kV transmission line providing market efficiency benefits, to be constructed between the existing Duff substation in Indiana and the existing Coleman substation in Kentucky (the “Project”). The Project has an expected in-service date of June 2020.
The formula rate has some innovative approaches in order to incorporate the results of the competitive process. The formula rate includes:
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.