On December 21, 2021, in Docket No. ER21-2882, FERC denied Pacific Gas and Electric’s (“PG&E”) request to recover 50% of the abandoned plant costs associated with three projects which CAISO had not canceled but had changed the scope. PG&E had requested authorization to recover 50% of abandoned plant costs associated with three transmission projects that the CAISO approved and then subsequently modified: (1) the Spring/Morgan Hill Area Reinforcement Project (Spring/Morgan Hill Project), (2) Oro Loma 70 kV Reinforcement Project (Oro Loma Project), and (3) Lockeford–Lodi 230 kV Area Development Project (Lockeford–Lodi Project) (collectively, Projects). PG&E explains that it identified the project costs it seeks to recover by forming a Project Cost Review Team (Review Team) that was responsible for assessing the costs of the Projects. The Review Team evaluated PG&E’s work for the Projects as originally designed and compared them with the scope of each revised Project to identify those costs that would no longer be useful for the rescoped Projects. PG&E sought recovery of 50% of the approximately $11.8 million ($5.89 million) the Review Team determined were no longer useful to the rescoped Projects, with PG&E writing off the remaining $5.89 million.
PG&E did not assert that CAISO had recommended abandonment of any of the Projects, but rather that the “rescoping” of the Projects through CAISO’s regional transmission planning process had resulted in a reduction in size and cost of the Projects to such an extent that the originally conceived Projects have been “essentially cancelled” and, therefore, should be eligible for abandoned plant cost recovery treatment under Opinion No. 295. However, PG&E cited no authority to support its theory that the Commission should permit such cost recovery where projects have been “rescoped,” and FERC saw no reason here to deviate from the Commission’s well-established policy. The Projects are designated as active and ongoing within CAISO’s 2020-2021 Transmission Plan, and CAISO has assigned 2025 and 2026 expected in-service dates for them. Therefore, FERC found that the Projects have not been abandoned and do not qualify for abandoned plant cost recovery treatment pursuant to Opinion No. 295. Further, unlike in situations where projects have been abandoned, the Commission’s accounting procedures provide for the capitalization of construction costs once the Projects go into service; therefore, PG&E will have the opportunity to seek recovery of the relevant costs at that time.
On December 16, 2021, in Docket RM20-16, FERC issued a final rule on Managing Transmission Line Ratings (Order 881). Through this rule, FERC is requiring:
FERC defines a transmission line rating as the maximum transfer capability, computed in accordance with a written methodology and good utility practices, considering the technical limitations on conductors and other equipment (thermal flow limits), as well as technical limitations of the transmission system (voltage and stability limitations). The transfer capability of a transmission line can change with ambient weather conditions. Increases in temperature lower the transfer capability while decreases in temperature increase transfer capability. The continued use of seasonal or static transmission line ratings based upon conservative, worst-case assumptions, results in suboptimization of the transmission line.
FERC requires the following:
Though not ordered in this proceeding, FERC initiated a subsequent proceeding, Docket No. AD22-5, to consider dynamic line ratings (“DLR”), which presents opportunities for transmission line ratings that are more accurate than those established with AARs. Unlike AARs, DLRs are based not only on forecasted ambient air temperatures and the presence or absence of solar heating, but also on other weather conditions such as (but not limited to) wind, cloud cover, solar heating intensity (instead of mere daytime/nighttime distinctions used in AARs), and precipitation, and/or on transmission line conditions such as tension or sag. FERC adopted the definition of DLR as a transmission line rating that: (1) applies to a period of not greater than one hour; and (2) reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar heating intensity, transmission line tension, or transmission line sag.
In this rule, FERC also requires transmission providers to use uniquely determined emergency ratings for contingency analysis in the operations horizon and in post-contingency simulations of constraints. Such uniquely determined emergency ratings must also incorporate an adjustment for ambient air temperature and daytime/nighttime solar heating, consistent with our AAR requirements for normal ratings. Most transmission equipment can withstand high currents for short periods of time without sustaining damage. Emergency ratings reflect this technical capability, defining the specific additional current that a transmission line can withstand and for what duration the transmission line can withstand that additional current without sustaining damage. Because emergency ratings reflect this capability, uniquely determined emergency ratings will ensure more accurate transmission line ratings.
FERC requires each transmission provider to submit a compliance filing within 120 days of the effective date of this final rule, revising their OATT to incorporate pro forma OATT Attachment M. FERC further require that all requirements adopted in the rule be fully implemented no later than three years from the compliance filing due date.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.