Pacific Gas & Electric (PG&E) did not provide enough information about the eight different transmission projects for which it sought incentive rate treatment from FERC, the California Public Utilities Commission (CPUC) and others claimed in protests filed with FERC April 11.
The eight different projects, all of which are 230-kV or lower, most of which involve substation work and none of which appears to be longer than 50 miles, lack the most basic information required to support the utility’s claim that they present “significant risks” warranting the incentive rate treatment, the CPUC said.
PG&E, a subsidiary of PG&E Corp. (NYSE:PCG), made the incentive rate treatment request on March 10, seeking a declaratory order from FERC that eight “greenfield” transmission projects that have been approved through the California ISO (Cal-ISO) planning process face significant risks and challenges in that major portions of each project will not be within existing rights of way (ROW). The challenges include environmental permitting reviews, siting authority reviews and potential changes from California’s expanding renewable energy goals, the utility told FERC.
PG&E sought recovery of 100% of all prudently incurred costs, including costs incurred prior to the date of the FERC filing, if any of the projects are abandoned or cancelled, in whole or in part, for reasons beyond PG&E’s control. It also sought a 50 basis point adder to be applicable to its base return on equity (ROE) for participation in a regional transmission organization due to its membership in the Cal-ISO.
The eight projects listed are:
The Wheeler Ridge Junction Project, a new 230/115-kV substation called the Casa Loma substation, and associated transmission lines in the Bakersfield area to provide additional transmission capacity in Kern County and provide PG&E’s Wheeler Ridge substation with a more reliable 230-kV source and mitigate voltage concerns.
The Spring 230-kV substation, which would consist of a new 230/115-kV substation and related transmission lines west of the existing Morgan Hill substation to reduce the reliance on local generation and eliminate blackout concerns in the event of a double-circuit outage.
The Estrella 230-kV substation, which would add a new substation east of the existing Paso Robles substation and provide an additional source for the Morro Bay-Gates 230-kV line.
The Martin 230-kV Bus Extension, which would reinforce the San Francisco peninsula through a reconfiguration of the existing 230-kV transmission system terminating at the existing Martin substation, bypassing the substation.
The Northern Fresno 115-kV Reinforcement, which would consist of a new 230/115-kV substation and associated transmission lines, along with 49 miles of reconductoring of various 115-kV lines near Fresno.
The Midway-Andrew 230-kV Project, involving a new 230/115-kV Andrew substation and transmission upgrades around the city of Santa Maria to address voltage collapse problems.
The Lockeford-Lodi Area 230-kV Development, which would create a new double-circuit of the Eight Mile-Lockeford 230-kV line, with one of the circuits looping into a new switching station outside the existing Lodi substation and create a new interconnection with Lodi Electric Utility.
The Oro Loma Reinforcement Project, which would loop the existing Los Bano-Panoche #2 230-kV circuit into a new substation, a distance of about two miles, and replace 10 miles of existing wood poles on a 70-kV line with tubular steel poles supporting a double-circuit 70-kV line, along with some additional facility upgrades.
PG&E said that the projects have been approved under various transmission plans addressed by the Cal-ISO, and that because they are “greenfield” projects requiring regulatory approvals and new ROW, they face cost escalation risks, the need for long lead time to acquire equipment and market risks that make the incentive rate request reasonable.
But the Transmission Agency of Northern California (TANC), the CPUC and the cities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside (collectively, the Six Cities) filed separate protests at FERC April 11. The protests centered around the notion that PG&E provided scant information about the projects and did not comply with FERC regulations that say incentive rate treatment is merited based on an applicant tailoring the request for demonstrable risks for each project.
Rather than a specific showing of why each project faces a risk, PG&E grouped its discussion of the projects together and gave FERC a broad description of various challenges it may encounter in developing the projects, the Six Cities said.
Several of the projects have been pending for multiple years, with the Oro Loma Reinforcement Project approved by the Cal-ISO in 2011, and PG&E could have sought to obtain certainty on their eligibility for incentives individually, the Six Cities said.
The Six Cities said FERC should not authorize recovery of 100% of prudently incurred costs before any order is issued on the request. For costs incurred by PG&E before that, FERC should allow PG&E to recover from ratepayers 50% of the costs, consistent with FERC policy on non-incentive ratemaking covering abandonment costs, the cities said.
The idea that basic regulatory approvals that are needed for routine transmission projects presents risks and challenges deserving incentive rates was challenged by the CPUC.
FERC Order 679, which lays out the incentive rate policy, “is clear that incentives are not intended to be a ‘bonus’ for good behavior, or to reward a utility for making ‘routine’ investments,” the CPUC said, asserting that FERC should reject PG&E’s petition.
Without much information on the length or cost of the projects, PG&E does not provide any evidence that the projects are anything more than routine projects that it would be required to pursue in the ordinary course of its business to ensure reliability, the CPUC said.
Like the Six Cities, TANC said FERC should not grant recovery of 100% of prudently incurred costs before the date any order is issued on PG&E’s request, and that any costs incurred before a FERC order should be split 50/50 between PG&E shareholders and ratepayers.
The risks PG&E listed were known to the utility well ahead of its filing with FERC, and PG&E provided no justification consistent with FERC policy for receiving the abandonment incentive, TANC said.