In Docket AC20-103, earlier in 2020, the law firm of Locke and Lord filed with FERC a request for FERC to provide guidance on the proper accounting for wind, solar facilities, and other non-hydro renewable resources. FERC denied this request but acknowledged that the industry would benefit from its guidance on the accounting treatment of solar and wind generating assets. To that end, on January 19, 2021, FERC initiated a Notice of Inquiry (NOI) in Docket RM20-19 in which FERC is soliciting input from interested parties to evaluate the need for accounting guidance and to consider creating separate categories of accounts for wind and solar generating assets. First, FERC seeks comments on whether to create new accounts within the Uniform System of Accounts (USofA) for non-hydro renewable energy generating assets, and, if so, how such accounts should be organized. Second, FERC seeks comments on how to modify FERC Form No. 1 to reflect any new accounts. Third, FERC seeks comments on whether to codify the proper accounting treatment of the purchase, generation, and use of renewable energy credits (RECs). Finally, FERC seeks comments on the rate setting implications of these potential accounting and reporting changes. Comments are due in mid-March and responsive comments due mid-April.
 Non-hydro renewable assets, as referred to in this notice, are production assets other than hydroelectric generators such as solar, wind energy, geothermal, biomass, etc., that rely on the heat or motion of the earth or sun’s radiation to produce energy. Specifically, these are denoted as renewable because the power production is based on a fuel source that is not consumed or destroyed by the generation process, such as buried hydrocarbons (coal, oil, natural gas), or the decay of rare irradiated heavy metals (nuclear). Biomass (trees, nut shells, grain husks and stalks, etc.) is considered renewable, despite its hydrocarbon source being consumed, due to its carbon release being offset by regrowth of carbon capturing equivalent biomass.
Addendum: On March 3, FERC issued an Order in this proceeding. FERC found, among other things, that they were not persuaded that Morongo Transmission should receive an RTO Adder of 100 bp and provided the 50 bp RTO Adder typically granted for RTO membership.
In Docket No. ER21-669, on December 16, 2020, Morongo Transmission LLC (“Morongo”) requested a transmission formula rate for its investment in the West of Devers Upgrade Project (the “Project”), currently being developed by Southern California Edison Company (“SCE”). Morongo has entered into an agreement with SCE that provides Morongo with an option to enter a 30-year lease of a percentage of the transfer capability of a segment of the Project (the “Option”). To fund its interest, Morongo may choose to invest up to the greater of $400 million or 50% of the final estimated cost of the Project, in the
form of prepaid rent. The amount that Morongo chooses to invest will determine the amount of transfer capability that Morongo will turn over to the CAISO’s operational control. Most of the interests in Morongo are owned by the Morongo Band of Mission Indians (“Morongo Band”), a federally recognized American Indian Tribe exercising jurisdiction over lands within the boundaries of the Morongo Reservation (“Reservation”). The remainder of Morongo is owned by Coachella Partners LLC, a limited liability company formed for the purposes of facilitating and investing in the Project. Axium Coachella Holdings LLC (“Axium Coachella”), a Delaware limited liability company, owns 100% of the membership interests in Coachella Partners. Axium Coachella is a direct, wholly owned subsidiary of AxInfra US LP (“AxInfra”). AxInfra, an investment fund focused on infrastructure investments in the United States, is managed by Axium Infrastructure US Inc. (“Axium US”), acting on behalf of AxInfra’ s general partner, Axium US Partner LLC.
The Project will provide for the transmission of electricity between the Devers Substation (located
near Palm Springs, California), El Casco Substation (located near the City of Calimesa in Riverside
County, California), Vista Substation (located in the City of Grand Terrace, California), and San
Bernardino Substation (in San Bernardino County, California). The Project will allow SCE to
increase the power transfer capability of current transmission facilities by approximately 3,200
MW – from approximately 1,600 MW to 4,800 MW – thereby enabling the deliverability of
electrical power from renewable generation sources that require the Project to deliver energy to
California load, and improving the transfer capability for resource adequacy imports.
The Project is replacing existing transmission facilities, portions of which cross the Reservation.
At the time SCE began planning for the Project, it occupied a 300-foot wide, six-mile expired
right-of-way on the Reservation, pursuant to temporary licenses issued by the Morongo Band.
SCE requested that the Morongo Band agree to grant to SCE an expanded 50-year, six-mile,
right-of-way in the existing transmission corridor through the Reservation to construct the Project.
SCE lacked the ability to condemn the right-of-way because states (and therefore utilities) do not
have eminent domain authority on Indian reservations. As a means of resolving the impasse, the Morongo Band offered to agree to the grant a right-of-way through the Reservation on the existing transmission corridor if SCE gave Morongo (newly formed for purposes of the parties’ agreement) an option to finance a portion of the Project upon completion. This creative solution was modeled on the then-recently entered agreement between San Diego Gas and Electric and Citizens Energy for the Sunrise Powerlink Transmission Project. Morongo would hold an Option to lease a percentage of the transfer capability of the Project (the “Lease”). The agreement on the Option and the Lease by SCE and Morongo is the first of its kind between a transmission utility and an Indian tribe.
Morongo’s Transmission Revenue Requirement is established on a formulaic basis and is the sum of two parts: (1) Capital Costs and (2) Operating Costs. The annual Capital Cost revenue requirement is calculated based on Morongo’s annual capital costs of leasing the Transfer Capability, with the rate for annual capital cost recovery being fixed, and the sum of that fixed rate plus Morongo’s share of property taxes can be no higher than the rate that SCE would charge for Morongo’s interest in the Project absent Morongo’s participation in the Project. The annual Capital Cost revenue requirement will be
fixed and levelized for the 30-year term of the lease. The annual Capital Cost revenue requirement incorporates a hypothetical capital structure of 50% equity and 50% debt, previously allowed by FERC pursuant to a 2014 Declaratory Order. The operating costs included in the annual revenue requirement are those operating costs directly attributable to Morongo’s Transfer Capability for the Project. The operating costs include those costs SCE bills to Morongo as well as those costs Morongo incurs directly by managing and administering its Transfer Capability (“Operating Costs”). Morongo is proposing that the Operating Costs be billed to the CAISO on an estimated basis, with an annual after-the-fact true-up to actual costs.
Morongo proposes to use SCE’s current authorized return on equity of 10.3% as a proxy for Morongo’s base return on equity. Morongo requests that FERC grant a 100-basis point adder to Morongo’s base return on equity, based upon Morongo’s commitment to become a new member of CAISO and transfer
operational control of its transfer capability under the Lease to CAISO once the Project has been
placed in service and Morongo has exercised its Option and closed on the Lease. Morongo asserts that the 100-basis point RTO participation incentive is just and reasonable based upon FERC’s policy encouraging new investment in transmission infrastructure, benefits from Morongo’s participation in the Project and membership in the CAISO and risks specific to Morongo Transmission by comparison to SCE and other diversified transmission utilities. In Order No. 679, Morongo states that FERC did not make a finding on the appropriate size or duration of the RTO Participation incentive, with the result that transmission utilities seek, on a case-by-case basis, an RTO participation adder of a specific size. Additionally, Morongo requested a 100-basis point adder for joining the CAISO as FERC has proposed a standard RTO Participation adder of 100 basis points in its current NOPR.
This case was before FERC for review an audit finding in Docket No. FA15-16 related to AFUDC for a natural gas pipeline. FERC found that Dominion Energy Transmission’s (DETI) calculation of AFUDC is not consistent with FERC’s accounting regulations. FERC found that it was undisputed that from 2008 to the present period covered by the Audit Report, DETI’s short-term debt balances exceeded DETI’s CWIP balances. Per the regulations in GPI No. 3(17)(b) (like those for electric utilities), DETI should have calculated its AFUDC rate using only weighted average short-term debt rates. However, DETI instead used the consolidated balances for short-term debt and CWIP maintained by its parent entity, Dominion Energy Gas Holdings, which covered numerous subsidiaries in addition to DETI. DETI determined that, for these consolidated balances, the consolidated CWIP monthly balances exceeded consolidated short-term debt, and thus DETI applied cost rates for long-term debt, preferred stock, and common equity to a portion of its CWIP to arrive at an AFUDC rate. The AFUDC rate, determined by DETI, was above the AFUDC rate allowed under the Commission’s regulations, leading to over capitalization of AFUDC, from 2008 through 2015, by approximately $54.1 million in audit staff’s estimation (although DETI estimates the impact to be approximately $48 million). FERC found that nothing in the text of the Commission’s regulations found at GPI No. 3(17), or in Order No. 561, authorized DETI to exclude the fact that its book balances of short-term debt exceeded its book balances of CWIP. Therefore, per GPI No. 3(17), DETI’s AFUDC rate should have been calculated without reference to cost rates for long-term debt, preferred stock, or common equity. The amount of AFUDC calculated by DETI exceeded the maximum amount prescribed by the AFUDC formula, yet at no time did DETI seek authorization from FERC, as required by GPI No. 3(17), to exceed that maximum amount. As FERC held in another proceeding in which a regulated entity, without seeking its authorization, excluded its short-term debt balances from its AFUDC rate calculation: “[O]ur regulations are clear and explicit that short-term debt should be included in the calculation of AFUDC rates …. It was and is [the regulated entity’s] obligation to justify a departure, i.e., a waiver of those regulations and that policy, and [it] did not and has not done so.”
 Otter Tail Power Co., 119 FERC ¶ 61,217, at P 15 (2007).
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.