​On October 26, 2020, Baltimore Gas and Electric (BGE), a subsidiary of Exelon, filed in Docket No. ER21-214 revisions to its transmission formula rate to align calendar year revenue and revenue requirement in its Projected Annual Transmission Revenue Requirement and in its Annual True-up Adjustment.  To accomplish this alignment, BGE seeks to adjust the true-up mechanism in its Formula Rate to: (1) use actual revenues, rather than projected revenues, for a 12-month period as the basis for the true-up; and (2) true-up those actual revenues for a given January to December time period to actual costs for that same January to December time period, instead of truing up revenue projections for a June to May time period to actual costs for the January to December time period, as is done in BGE’s current transmission formula rate. This timing adjustment revision is consistent with FERC precedent and have been implemented for several utilities, including Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company (all Exelon subsidiaries). 
 
The filing also revises the method for developing the forecasted revenues for the upcoming year, which are used to establish BGE’s projected revenue requirement – the basis for its transmission rates. Under the new methodology, BGE will use projected values for plant, accumulated depreciation, depreciation and amortization expense, other income tax adjustment expense, and accumulated deferred income taxes (“ADIT”) for the upcoming year when developing its projected transmission revenue requirements. All rate base items in the projected and true-up revenue requirements will also be calculated using the average of 13 monthly balances with the exception of ADIT, which will use a simple average.6 Non-plant related rate base items and capital structure will continue to use historical data; however, this data will be 13-month average balances as opposed to year-end balances as done with the current Formula Rate.  To adhere to tax normalization rules, ADIT would reflect the application of proration rules.  Historical data will still be used for non-plant related rate base components of the projected revenue requirement (e.g., prepayments, reserves, materials and supplies), other expenses (e.g., Operating & Maintenance expenses and Taxes Other Than Income Taxes) and capital structure, as these items tend to have less year-to-year variability compared to plant-related items. 

On October 15, 2020, FERC issued Opinion 572 in Docket No. ER16-2320 on Pacific Gas and Electric’s (PG&E) 2018 electric transmission rate.  In this order, among other things, FERC directed further briefing regarding PG&E’s ROE (initial briefs shall be due in 60 days, with responses due 30 days later). 

1. PG&E had requested a 10.4% base ROE with a 50- basis point RTO Adder for a total ROE of 10.9%.  FERC decided to reopen the record here because FERC has proposed to change its approach for determining just and reasonable base ROEs since the administrative law judge provided an Initial Decision.  FERC provided the parties an opportunity to present written evidence concerning FERC’s revised ROE methodology adopted in Opinion Nos. 569 and 569-A, and whether and how that revised methodology should apply to the facts of this proceeding.
2. PG&E proposed to calculate its cost of debt by dividing the annual payments that it must make on each debt issuance by the net proceeds of the issuance, which is the face value of the debt minus the issuance costs and any cash discount.  This is referred to as the net proceeds’ method.  The ALJ concluded that FERC’s decision in System Energy Resources, Inc. (SERI) dictated using the gross proceeds of the debt issuance to calculate PG&E’s cost of debt, rather than net proceeds.  The ALJ explained that in SERI, the company proposed to use the net proceeds method to calculate the cost-of-debt component of its capital structure, arguing that use of the gross proceeds method caused the company to under-recover its cost.  FERC rejected this argument and held that the cost-of-debt component of capitalization should reflect the “company’s total obligation [to its creditors] with respect to long-term debt” and that the gross proceeds methodology “allows for a more accurate picture of [a company’s] capital structure and, in turn, results in the correct calculation of [a company’s] cost of capital.”  Because PG&E made no attempt to distinguish SERI in either of its post-hearing briefs, the Presiding Judge directed PG&E to use the gross proceeds method to recalculate its cost of debt.  However, the SERI decision addressed the use of gross proceeds for long-term debt principal outstanding to calculate the long-term debt ratio in the capital structure, not the long-term debt costs.  Accordingly, FERC found SERI is distinguishable from the facts for PG&E.  FERC has previously stated that cost of debt should be on a net proceeds basis so that the utility can fully recover the underwriter’s compensation and the expenses of financing.  Furthermore, section 35.13(h)(22)(ii)(a) of the Commission’s regulations states that “[t]he weighted cost [of long-term debt] is calculated by: (1) Multiplying the cost of money for each issue under clause (B)(6) below by the principal amount outstanding for each issue… and clause (B)(6) states that the “cost of money” is …the yield to maturity at issuance based on the interest rate and net proceeds to the utility determined by reference to any generally accepted table of bond yields.”  Accordingly, FERC found that the use of net proceeds to calculate the long-term debt cost rate is appropriate while use of the gross proceeds for inclusion in the capital structure is appropriate. 
3. The Commission has long held that “managers of a utility have broad discretion in conducting their business affairs and in incurring costs necessary to provide services to their customers” and that “the appropriate test to be used” in assessing the prudency of costs “is whether they are costs which a reasonable utility management…would have made, in good faith, under the same circumstances, and at the relevant point in time.”  Even if a decision turns out to be incorrect in hindsight, FERC’s task is to review the prudence of a utility’s actions and the costs resulting from the particular circumstances existing either at the time the costs were incurred or when the utility became committed to incur those expenses.  As FERC has also held, however, a presumption of prudence exists only until the challenging party creates a serious doubt as to the prudence of an expenditure.  If this occurs, the regulated entity has the burden of proof to establish prudence.  In this case, FERC found that the CPUC, which had challenged some of PG&E’s capital investments, failed to raise serious doubts about the prudency of PG&E’s capital expenditures, and in particular, the Embarcadero-Potrero Project expenditures, which is the only specifically identified transmission project for which CPUC makes a prudence challenge.  FERC agreed that, while CPUC raises concerns about the costs of the Embarcadero-Potrero Project, particularly the cost overruns from its initial forecast in the CPCN proceeding, any mistakes made by PG&E in developing this significant transmission project “do not constitute the kind of mismanagement that should raise serious doubts about the prudency of their expenditures.  Regarding the issue of PG&E’s “self-approved” projects, CPUC has failed to raise discrete issues and present specific evidence raising doubts pertaining to the prudency of capital costs of a specific transmission project.  As the Commission has explained, whether costs were prudently incurred is a fact-specific inquiry and the Commission must examine the prudency of specific costs.  It does not suffice to make general, sweeping allegations of imprudence without focusing on costs incurred with respect to specific transmission projects, as is the case with CPUC’s challenge to the “self-approved” projects.
4. PG&E allocates common, general, and intangible (CGI) plant costs in two steps.  First, whenever practical, PG&E identifies plant used by a single line of business and directly assigns that plant to the corresponding “Unbundled Cost Category” within which the line of business falls.  PG&E allocates the remaining, “residual” CGI plant costs to Unbundled Cost Categories based on a wage allocator.  FERC found that the Kern River test applies to the appropriateness of PG&E’s proposed direct assignment of CGI plant costs.  FERC found that any cost can be accounted for on a direct assignment basis regardless of the specific expense account, and that the test is specifically whether the method of directly assigning the cost is consistent and the relationship obvious and reviewable.  FERC found that PG&E failed to demonstrate that its direct-assignment methodology satisfies the Kern River test and ordered PG&E to allocate CGI costs using a wage allocator.    
5. FERC denied PG&E’s request to accept an alternate calculation of the 1/8th O&M after FERC rejected PG&E’s balance sheet working capital lead-lag study as deficient.  FERC found no basis to accept the alternate 1/8th O&M calculations that would result in a higher amount of cash working capital allowed in rate base than under the methodology proposed in PG&E’s filing.  

By Order dated March 27, 2020, in Docket No. ER20-276, FERC found that Prairie Power should use its actual capital structure of 19% equity and 81% debt to determine its transmission revenue requirement in its transmission formula rate rather than the hypothetical capital structure of 50% equity and 50% debt requested by Prairie Power.  Prairie Power requested rehearing.  In its Order on rehearing dated September 17, 2020, FERC sustained its March 27th Order, as FERC found that Prairie Power had failed to demonstrate that its situation warrants an exception to using its actual capital structure.  FERC stated that two circumstances demonstrate that a capital structure is anomalous and warrants the use of a hypothetical capital structure: when “(a) the capital structure of the financing entity is not representative of the regulated [entity’s] risk profile, or (b) the capital structure is different from the capital structure approved for other [regulated entities], or if a [discounted cash flow (DCF)] analysis is performed, outside the range of the proxy group used in the DCF analysis.”  With Prairie Power, the financing entity and the regulated entity are the same, and so the risk profile is identical.  When evaluating the second type of circumstance, the analysis “is performed primarily to determine if the equity component of the capital structure of the financing entity (either the pipeline or its parent) is atypically high” and “‘[i]n general, FERC does not impute equity because this can over compensate the equity holder at the expense of the ratepayer.’”  In addition, FERC reviewed all evidence and precedent that Prairie Power submitted – including responses to the deficiency letter regarding credit rating changes, financial metrics, and the effects of cost overruns – and concluded that Prairie Power had not justified its proposed departure from cost-based ratemaking. 
​
Last, FERC was unpersuaded by Prairie Power’s argument that the MISO base ROE for transmission owners, as a small component of Prairie Power’s overall return due to its low percentage equity, inadequately compensates Prairie Power for its risk and thus justifies the use of a hypothetical capital structure.  FERC stated that, to the extent that Prairie Power believes that its risks are not captured by the MISO transmission owners’ ROE in its actual capital structure, Prairie Power may file to request a different ROE under FPA section 205.     

On April 11, 2019, in FERC ER19-1553, Southern California Edison (SCE) filed changes to its transmission formula rate due to dramatic material changes to SCE’s regulatory and financial conditions that have occurred since SCE filed its currently effective Formula Rate (the “Second Formula Rate”) in October 2017.  Beginning in December 2017, several wind-driven wildfires impacted portions of SCE’s service territory and caused substantial damage to both residential and business properties and service outages for some of SCE’s customers. California has unique inverse condemnation laws. These laws provide that an electric utility will be held strictly liable for property damages and legal fees if its facilities are the substantial cause of a fire regardless of fault and even if the utility was fully compliant with all applicable rules and regulations and acted reasonably. As a result of these laws and recent fires, SCE is exposed to significant potential wildfire damage claims. In 2017, the California Public Utilities Commission (“CPUC”) issued a decision holding that it could preclude a utility from recovering these court-assigned costs if it finds the utility was not prudent, even if the source of the alleged imprudent conduct was not directly the cause of the fire.  The decision creates significant CPUC-related cost-recovery uncertainty and, as a result, SCE recently announced an accrual of a 2018 fourth quarter non-cash charge against earnings of $1.8 billion due to potential wildfire damages that would be dependent upon CPUC-approval.
 
SCE filed proposed revisions to its Formula Rate to account for the above risk in a manner sufficient to attract the capital necessary to provide safe and reliable electric service.  SCE requested a base ROE that is founded on, and fully supported by, FERC’s established ROE policies. SCE applied the four financial models utilized in the Commission’s October 2018 Order Directing Briefs in the New England Transmission Owner (NETO) ROE cases - which includes the Discounted Cash Flow (“DCF”) model, the Capital Asset Pricing Model (“CAPM”), the historical Risk Premium model, and Expected Earnings—and determined the ROE that is required to reflect the significant non-wildfire regulatory and legislative risks that SCE faces as a public electric utility operating in California.  That base ROE is 11.12%.  SCE also analyzed how the additional risks it faces as a result of wildfires affect SCE’s ability to attract capital. While these wildfire risks required additional analysis to complement the conventional application of the four financial models, this additional analysis is fully consistent with FERC’s rationale in the NETO Order Directing Briefs because this analysis connects SCE’s circumstance and its unique risks with the capital attraction standard that underlies the Commission’s ROE policies.  SCE accordingly requests an increase to its base ROE 0f 6.0% to account for the asymmetric wildfire risk (total base ROE of 17.12%).  SCE also asks that, in determining its capitalization and costs of capital, the charge to earnings described above ($1.8 B) be removed from its common equity balance along with any debt incurred related to the wildfire liabilities.  SCE’s proposed retail transmission revenue requirement for calendar year 2019 (effective June 12, 2019) is $1,328,294,741, which compares to the current amount for calendar year 2018 of $1,038,486,906.   

Recently FERC has issued orders directing TOs to eliminate the two-step approach for addressing ADIT in formula rates with projections.  Previously, many TOs believed that the IRS required, for projecting ADIT balances, use of its proration methodology and then, in addition, use of the conventional 13-month averaging to that proration result.  TOs thought the averaging was necessary in order to meet the IRS’ consistency requirements.  In April 2017, the IRS issued a Private Letter Ruling (PLR) in which it clarified that the averaging, in addition to the proration methodology, was unnecessary.  Thus TOs have been making filings to eliminate the averaging from the ADIT projection.
 
For the True-up calculation, all TOs have held that the IRS proration requirement does not apply to the calculation of the revenue to which the utility would have been entitled had it based its projected rate computation on what turned out to be the actual results for that period. The result is to ignore proration in the True-up calculation and reverse the impact of the application of the proration requirement embedded in the projected rate calculation (i.e., the true-up would be to a revenue number that did not reflect any proration). However, in the PLR, the IRS said that to make proration matter, the freedom from proration can only apply to the variations in the changes in the ADIT balance used in the True-Up component, not to the entire change in the ADIT balances used in that computation. The IRS stated that the True-Up component is determined by reference to a purely historical period and, accordingly, there is no need to use the proration formula to calculate the differences between projected ADIT balance and the actual ADIT balance during the period. In calculating the True-Up, proration applies to the original projection amount, but the actual amount added to the ADIT over the test year is not modified by application of the proration formula.
 
ATC proposed to FERC in EL18-157 not to apply the proration formula to the variances in the monthly ADIT balances but, instead, to apply its “normal” regulatory convention (a 13-month average) to those variances. ATC proposed to add the result of this calculation to the ADIT balance originally used in the calculation of the projected rate – that is, the prorated balance. In this way, ATC would preserve the effect of the proration requirement embedded in the projected rate, avoid applying proration to the differences between projected and actual ADIT balances and comply with the consistency rule with respect to those variances.   

GridLiance and Certain MISO TOs take a different and more complicated approach in the True-up calculation.  The differences attributable to over-projection of ADIT in the annual projection will result in a proportionate reversal of the projected prorated ADIT activity to the extent of the over-projection.  The differences attributable to under-projection of ADIT in the annual projection will result in an adjustment to the projected prorated ADIT activity by the difference between the projected monthly activity and the actual monthly activity.  However, when projected monthly ADIT activity is an increase and actual monthly ADIT activity is a decrease, actual monthly ADIT activity will be used.  Likewise, when projected monthly ADIT activity is a decrease and actual monthly ADIT activity is an increase, actual monthly ADIT activity will be used.  

Please contact Dumais Consulting if you want to see examples of both approaches.

​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[1]. 
 
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.

[1] 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.  

​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:
 

1. Previously approved incentives in EL17-52, including deferred recovery of prudently incurred pre-commercial costs through creation of a regulatory asset; full recovery of prudently-incurred costs if the Project is abandoned for reasons beyond Republic’s control; use of a hypothetical capital structure consisting of 55% debt and 45% equity until the Project achieves commercial operation; and a 50 basis point adder to Republic’s return on equity for participating in MISO, subject to an overall return on equity cap described below;
2. A total rate base cap of $58.1 million, inclusive of all costs necessary to develop, construct, and place the project in-service including escalation and AFUDC;
3. A ROE cap at the lesser of 9.80% inclusive of incentives or the MISO region-wide base ROE plus an RTO participation adder.  If the MISO region-wide base ROE plus Republic’s RTO adder is below 9.80%, then that is the ROE;
4. A schedule guarantee under which the ROE will be reduced if the schedule is not met.  In the event the completion date is later than January 1, 2021, subject to extension due to events outside of Republic’s control, Republic will decrease its Project-specific ROE for every month of delay, up to a total of 30 basis points for a delay of 12 months or longer. To the extent that the schedule guarantee results in a reduction in the Project ROE, the reduction is for the life of the Project.; and
5. An Equity Percentage Cap of 45% that applies for the life of the Project.  The equity ratio is the lessor of actual or 45%.

​In an order issued June 21, 2018, FERC instituted a section 206 proceedings to examine the methodology utilized by Ameren Illinois, Ameren Transmission of Illinois, and Northern States Power Company, for calculating Accumulated Deferred Income Tax (ADIT) balances in their projected test year or annual true-up calculations for their electric transmission formula rates.  In a June 2018 Order, FERC explained that in light of the IRS April 2017 Private Letter Ruling, FERC undertook a review of Commission-jurisdictional transmission formula rates and identified Ameren, NSP Companies, and other transmission owners who currently use the two-step averaging methodology to calculate the ADIT component of rate base in their projected test year calculations or annual true-up calculations for their transmission formula rates.  The two-step approach involves projecting ADIT balances using the prescribed IRS proration approach (Step 1) and then averaging the beginning and ending projected ADIT amounts from Step 1 (Step 2).  FERC concluded that if the IRS’s proration methodology is applied to calculate ADIT balances in forward-looking formula rates, then the additional averaging step (Step 2) is not needed need to comply with the Consistency Rule (using same methodology to project tax expenses, depreciation expenses, ADIT and rate base).  Thus, the two-step averaging methodology is not necessary to comply with the IRS Normalization Rules and results in understating ADIT balances and overstating rate base and revenue requirements.  Several transmission owners, in addition to Ameren and Northern States (Public Service Company of Colorado, Southwestern Public Service Company,  ALLETE, Montana-Dakota Utilities Co., Northern Indiana Public Service Company, Otter Tail Power Company, Southern Indiana Gas & Electric Company, International Transmission Company, ITC Midwest, Michigan Electric Transmission Company, American Transmission Company, TransCanyon DCR, Virginia Electric and Power Company, GridLiance and Southern California Edison) filed changes which FERC approved), or were ordered to file changes, to their transmission formula rates to eliminate the second step (averaging of the prorated balances). 
 
For the orders, please click on the link below:
 
https://www.ferc.gov/whats-new/comm-meet/2018/ca12-20-18.asp?csrt=7821894867607656177
   

On November 15, 2018, FERC issued a Notice of Proposed Rulemaking (NOPR), a policy statement, and several orders implementing individual rate revisions and reductions to reflect the impact of Tax Reform in transmission formula rates. The NOPR (RM19-5-000) proposes to require each transmission provider with transmission rates under an Open Access Transmission Tariff , a transmission owner tariff or a rate schedule to revise those rates to account for changes caused by the Tax Cuts and Jobs Act. These proposed reforms are designed to address the tax law’s effects on the Accumulated Deferred Income Taxes (ADIT) reflected in their transmission rates. Under these reforms, all public utilities with transmission formula rates would: 
·      include mechanisms to deduct any excess ADIT from or add any deficient ADIT to their rate bases;
·      include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT; and
·      incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT.
All public utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. Comments are due 30 days from when the NOPR is published in the Federal Register.  Here is the link to the NOPR: https://www.ferc.gov/whats-new/comm-meet/2018/111518/E-1.pdf?csrt=13550044115908092740.
FERC also issued a policy statement (PL19-2-000) which provides accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities, natural gas pipelines and oil pipelines. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017.  Here is the link to the Policy Statement: https://www.ferc.gov/whats-new/comm-meet/2018/111518/E-1.pdf?csrt=13550044115908092740.
FERC also approved an accounting request from the Edison Electric Institute (AC18-59-000) related to recording a reclassification of any stranded tax effects from Tax Reform. Lastly, FERC acted on 46 of the Federal Power Act section 206 show-cause investigations initiated in March, in which the Commission directed certain public utilities whose transmission tariffs specifically reference tax rates of 35 percent to reduce their tax rates to 21 percent or show why they did not need to do so.
Dumais Consulting welcomes the opportunity to help entities with comments to FERC on the NOPR and in complying with the eventual requirements both for accounting and electric transmission in formula rates. Please contact Dumais Consulting at www.DumaisConsulting.com.