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.  

​PG&E requested an expedited decision from FERC on its request in Docket No. AC19-122 whereby PG&E proposed to determine its AFUDC rate in a manner that excludes certain liability provisions required by GAAP that do not have an impact on cash available to fund construction. Specifically, PG&E had requested the Commission’s authorization to exclude from the AFUDC rate formula calculation the 2017 Northern California Wildfires and the 2018 Camp Fire contingent liabilities, net of accrued insurance proceeds and accrued tax benefits (and any future regulatory asset offset), from its equity balance (i.e., capital structure calculation).  On October 15, 2020, PG&E filed an Offer of Settlement and Stipulation (Settlement) in its Formula Rate Proceedings (ER19-13, ER19-1816 and ER20-2265) which included adjustments to PG&E’s regulatory capital structure used in its Formula Rate.  In the Settlement, the Parties agreed to a fixed capital structure for use in the Formula Rate with common stock being fixed at 49.75%, preferred stock being fixed at 0.5%, and long-term debt being fixed at 49.75%.  The Parties also agreed that this capital structure should be used in PG&E’s AFUDC calculation for the permanent capital component of the AFUDC rate.  As a result, PG&E revised its request in Docket No. AC19-122 to reflect the terms of the settlement as to how the AFUDC calculation adjustment to the permanent capital component (i.e., non short-term debt) of the AFUDC rate be determined.  PG&E requested that these changes apply to AFUDC calculations effective as of May 1, 2019 through June 30, 2020 as the 2017 Northern California Wildfires and the 2018 Camp Fire contingent liabilities were paid upon PG&E’s emergence from bankruptcy on July 1, 2020. 

​On October 15, 2029, in Docket No. ER20-1783, FERC approved a request by NEET MidAtlantic Indiana for a formula rate that accommodates its acquisition of certain transmission facilities from Commonwealth Edison Company of Indiana, Inc. (ComEd) and rejected its request to establish a regulatory asset for transaction costs related to the acquisition.  FERC approved the tariff changes to become effective upon the date NEET MidAtlantic Indiana becomes a transmission-owning member in PJM.  FERC denied NEET MidAtlantic Indiana’s request for pre-approval to record the transaction costs as regulatory assets as the transaction costs at issue here are not the type of incentives, such as formation and pre-commercial costs related to competition for transmission enhancements as part of the RTEP process, that the Commission has previously found further the policy goal of facilitating the participation of nonincumbent transmission developers in transmission planning processes, thereby encouraging competition.  Rather these costs are associated with the acquisition of existing transmission assets.  FERC’s policy is to accept acquisition adjustments in rate base, and thus allow their recovery, only if utility can show that “the investment decision is prudent and if it can demonstrate that the acquisition provides measurable benefits to ratepayers.”  To recover such acquisition adjustments, the utility must show specific, tangible, non-speculative, quantifiable benefits in monetary terms, which NEET MidAtlantic Indiana did not do.