FERC Rejects PacifiCorp's Proposed Wind Integration Charge

August 20, 2013

On August 15, 2013, the Federal Energy Regulatory Commission (FERC) rejected without prejudice PacifiCorp’s proposal to charge variable energy resources (VERs), including wind generating facilities, a higher rate for Regulation and Frequency Response Service (Regulation) than conventional, dispatchable generators.  FERC held that PacifiCorp’s differentiated generator Regulation charge proposal, the first filed by a public utility transmission provider since FERC’s VER rulemaking, failed to adequately address or account for cost savings associated with the operational reforms required by Order No. 764, including intra-hour scheduling practices that have already been implemented on PacifiCorp’s system.


BACKGROUND

In Order No. 890, FERC recognized that the ancillary service rate schedules contained in FERC’s pro forma Open Access Transmission Tariff (OATT) may not allow a transmission provider to recover the fixed cost of generation capacity that must be made available to respond to and balance the short term variability of generation resources, particularly where such resources are exported outside of the transmission provider’s balancing authority area (BAA).  FERC held that transmission providers could propose generator Regulation charges to recover these costs from generators and that FERC would evaluate the proposals on a case-by-case basis.  In Westar Energy, Inc., 130 FERC ¶ 61,215 (2010), FERC approved, for the first time, a differentiated generator Regulation charge that assessed a higher charge on VERs than conventional generators based on data demonstrating VERs’ disproportionate variability.  The Commission approved a settlement in Puget Sound Energy, Inc., 142 FERC ¶ 61,018 (2013) authorizing a differentiated generator Regulation rate schedule similar to that approved in Westar.      

In Order No. 764, FERC again recognized the need to permit transmission providers cost recovery for VER integration costs but declined to adopt a generic approach that would have added a new Schedule 10 to the pro forma OATT for recovery of generator Regulation costs, choosing instead to continue its case-by-case review of generator Regulation charges.  FERC did require transmission providers to implement operational reforms designed to reduce VER integration costs, including: (i) offering customers the option to submit transmission schedules at 15-minute intervals within the hour; and (ii) requiring new VERs to report certain meteorological and forced outage data to transmission providers for power production forecasting.   In Order No. 764-A, FERC clarified that it “sought to achieve a balanced approach that emphasizes public utility transmission providers’ obligation to take the intra-hour scheduling and forecasting reforms into account” in supporting rates for generator Regulation service.  FERC did not, however, expressly require utilities to collect a year’s worth of operational data after the implementation of Order No. 764’s operational reforms in order to charge VERs a higher rate for Regulation service, as was proposed in the Notice of Proposed Rulemaking.  FERC also extended the deadline for compliance with Order No. 764’s operational reforms to November 12, 2013.

PACIFICORP’S FILING

On April 1, 2013, PacifiCorp filed proposed changes to its load and generator Regulation charges under Schedules 3 and 3A of its OATT.  Under the existing rate schedules, which stemmed from a February 2013 settlement agreement, PacifiCorp assessed a single charge of $2.90/kW-year for load under Schedule 3, and to generators exporting power outside of PacifiCorp’s BAA under Schedule 3A.  In its April filing, PacifiCorp proposed to charge load $4.16/kW-year under Schedule 3, VER generators $8.25/kW-year under Schedule 3A, and dispatchable generators $0.001/kW-year (also under Schedule 3A). 

To determine these differentiated Regulation charges, PacifiCorp followed a methodology similar to that used by Westar and Puget Sound Energy.  Using twelve months of data from 2011, PacifiCorp determined the quantity of Regulation reserves required to be available to respond to the variability of load, VERs, and dispatchable generators, respectively, by comparing hourly operational forecasts to actual load and generator output over 10-minute increments and using a 99.7% confidence interval.  PacifiCorp then multiplied the Regulation reserve quantities by a fixed capacity charge of $96.726/kW-year, based on the cost of PacifiCorp’s generating units weighted according to their participation in providing Regulation service.  PacifiCorp then divided these annual revenue requirements for load, VERs, and dispatchable generation by total system load and installed capacity of VERs and dispatchable generators, respectively, to arrive at the per-unit charges contained in Schedules 3 and 3A.  

PacifiCorp’s filing was vigorously protested by numerous parties, including the American Wind Energy Association, Solar Energy Industries Assocation, Iberdola, NextEra and the Bonneville Power Administration.  The protests largely took issue with PacifiCorp’s use of stale data, and failure to account for anticipated cost reductions that could result from the implementation of Order No. 764’s operational reforms. 

FERC'S ORDER REJECTING THE FILING

FERC rejected PacifiCorp’s proposed revisions to Schedules 3 and 3A without prejudice, finding the rate changes were not shown to be just and reasonable.  FERC did not engage in an in-depth analysis of PacifiCorp’s methodology for determining the proposed differentiated Regulation charges.  Rather, central to FERC’s holding was PacifiCorp’s use of 2011 data to determine the quantity of Regulation reserves needed to respond to VER variability in PacifiCorp’s BAAs.  Intra-hour scheduling (on the half-hour, as well as the hour) were first offered to PacifiCorp customers during the 2011 test year but were not yet widely used, and FERC found that “PacifiCorp should have determined if any correction to its rates was needed given the difference in operational practices for most of 2011 and the operational practices in place today.”  FERC also faulted PacifiCorp for “limit[ing] itself to preliminary analysis and vague statements regarding the operational reforms of Order No. 764.”  

IMPLICATIONS

PacifiCorp filed its proposed differentiated Regulation charges during the somewhat awkward, intermediary period between Order No. 764’s issuance and the looming November 12, 2013 compliance deadline for utilities to implement 15-minute scheduling and power production forecasting.  While FERC could not reject PacifiCorp's filing solely because PacifiCorp has not implemented reforms that are not yet required of it, FERC appears to have penalized PacifiCorp for failing to adjust its rates for the intra-hour scheduling optionality that had already been implemented by PacifiCorp.  It’s interesting to note that the settlement in Puget included discounts for consistent intra-hour scheduling behavior.  FERC could have accepted PacifiCorp’s filing, suspended it, and made it subject to refund and hearing procedures to resolve this rate issue.  Instead, it rejected the filing “without prejudice.”  FERC appears to be sending a signal to transmission providers to heed FERC’s statement in Order No. 764-A that, “in reviewing any future proposal to allocate a greater quantity of capacity costs to a particular set of transmission customers, it would be reasonable for the Commission to consider whether the public utility transmission provider has taken steps to mitigate such costs” through operational reforms.     

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For additional information, please contact Gary Bachman, Richard Bonnifield, Justin Moeller, or any member of the firm’s Electric Practice at (202) 298-1800 in Washington, D.C. or in Seattle at (206) 623-9372.