FERC Finalizes Variable Energy Resource Integration Rule

June 26, 2012

By Rich Bonnifield, David Yaffe, Van Smith, and Gabe Tabak

On June 22, 2012, the Federal Energy Regulatory Commission (FERC) issued Order No. 764, a final rule adopting reforms to facilitate the integration of variable energy resources (VER or VERs) into the electric grid.  The Final Rule reflects a more modest set of revisions than initially proposed and has only two required elements:  (1) the pro forma Open Access Transmission Tariff (OATT) is amended to require that transmission providers allow 15-minute intra-hourly scheduling of transmission service by all transmission customers that desire to make such intra-hour scheduling additions or changes; and (2) the pro forma Large Generator Interconnection Agreement (LGIA) is modified to require new VERinterconnection customers to provide meteorological and forced outage data to the transmission providers if the transmission provider needs the data for power production forecasting.  FERC declined to adopt the third proposal made in its Notice of Proposed Rulemaking, which would have added a new ancillary service rate schedule (Schedule 10 - Generator Regulation and Frequency Response Service) to the pro forma OATT.  FERC instead stated that it will continue to take a case-by-case approach in evaluating such generator regulation charges and provided guidance about the factors that should underlie a proposed generator regulation charge.  FERC-jurisdictional transmission providers must make a compliance filing relating to the first two requirements within twelve months from the date that Order No. 764 is published in the Federal Register.


According to the definition in the Final Rule, a VER “is a device for the production of electricity that is characterized by an energy source that:  (1) is renewable; (2) cannot be stored by the facility owner or operator; and (3) has variability that is beyond the control of the facility owner or operator.”  VERsinclude wind and solar generation facilities, among other resources.  The inability of generators to dispatch facilities and the variability of output present challenges to integrating renewable generators that FERC has attempted to address several times during the last few years. 

In November 2010, FERC issued a Notice of Proposed Rulemaking (NOPR) proposing three reforms to eliminate operational procedures that have the de facto effect of imposing an undue burden onVERs.  (For further details, see November 22, 2010 VNF alert entitled “FERC Proposes Revisions to the Pro Forma OATT to Facilitate the Integration of Renewable Generation Facilities”).  First, FERC proposed to amend the pro forma OATT to provide transmission customers the option to schedule transmission service on a 15-minute, intra-hourly basis.  Second, FERC proposed to amend the proforma LGIA to require new VER interconnection customers to provide meteorological and forced outage data to transmission providers with whom they are interconnected, where the transmission provider relies upon power production forecasting.  Third, FERC proposed to add a new ancillary service rate schedule (Schedule 10 - Generator Regulation and Frequency

Response Service) to the pro forma OATT to clarify how generator regulation costs are recovered.  FERC proposed that cost recovery under the proposed Schedule 10 be similar to that of the existing Schedule 3, with a single per-unit rate for regulation reserve capacity equal to the FERC-approved per-unit rate under Schedule 3, and a volumetric component to allocate the total regulation reserve capacity among load and generation, in a manner consistent with cost causation principles.  FERC proposed to permit a transmission provider to assess a different volumetric component for VERs under Schedule 10 only where fully supported by data collected over a one-year period in which the transmission provider has fully implemented (1) 15-minute intra-hourly scheduling and (2) power production forecasting.


Transmission Providers Must Offer 15-Minute Scheduling:  The Final Rule adopts the NOPR’s proposal on scheduling, and amends the pro forma OATT to require that all transmission customers have the option to schedule transmission service at 15-minute intervals.  The Final Rule does not require that transmission providers convert to 15-minute scheduling for all transmission customers; it simply requires transmission providers to offer such schedules to all customers.  In light of substantial comments highlighting the variety of potential complications of requiring transmission providers to change more about their scheduling procedures than simply permitting VERs to adjust their schedules on a 15-minute basis, FERC decided not to require conforming changes to transmission products, imbalance settlement, or sub-hourly dispatch.  The Final Rule permits transmission providers to recover costs associated with implementing intra-hour scheduling under Schedule 1 (Scheduling, System Control and Dispatch Service) of the pro forma OATT.  The Final Rule also allows transmission providers to develop alternative scheduling proposals to the extent the pro forma changes are problematic, but the transmission provider bears the burden to establish that the alternative provides comparable or greater relief from imbalance charges and reserve-related costs and is consistent with regional scheduling practices.  Based upon past precedent this is a heavy burden.

Obligation of VERs to Provide Meteorological and Forced Outage Data to Transmission Providers: The Final Rule amends the pro forma LGIA to require that new VER interconnection customers after the effective date of a transmission provider’s compliance filing provide meteorological and forced outage data to the transmission providers to which they are interconnected, if the transmission provider requires that data for power production forecasting.  However, there is no obligation for interconnection customers to provide such data where the transmission provider is not engaged in power production forecasting. 

The Final Rule takes a flexible approach to data reporting, with certain categories of required data for wind (temperature, wind speed, wind direction, and atmospheric pressure) and solar generators (temperature, atmospheric pressure, and irradiance), and declines to adopt the NOPR’s proposal to report such data at or near real-time, instead leaving the frequency and timing of data submittals to be negotiated by the parties.  Further, the Final Rule declines to adopt the NOPR’s proposed forced outage threshold of 1 MW or more for 15 minutes or more, and instead requires forced outage reporting to align with the power production forecasting being employed by the transmission provider.

Commentary on the Design of a VER Generation Regulation Charge:  The Final Rule declines to adopt the proposed pro forma rate schedule for generation regulation service because it could inhibit flexibility in designing capacity services that align with the operational needs of transmission providers.  Instead, FERC will continue to evaluate proposals to recover generator regulation service on a case-by-case basis.  The Final Rule supplies guidance, however, on how FERC will review proposals for cost recovery of generation regulation service.  A transmission provider may include opportunity costs for generator regulation service (the costs of holding generating capacity in reserve, rather than producing power for sale).  Further, in evaluating whether to permit differing regulation reserve rates (i.e. a greater volumetric rate for VERs as compared to traditional resources), FERC will consider whether the transmission provider:

  • Distinguishes customers into classes reasonably related to operational characteristics;
  • Provides a detailed explanation as to why such classifications are appropriate;
  • Demonstrates that it has accounted for diversity benefits among all resources and loads;
  • Incorporates the diversity benefits of weather events such as droughts;
  • Considers the extent to which transmission customers are using 15-minute intra-hourly scheduling;
  • Addresses the implementation of power production forecasting, explains how the data required fromVERs are incorporated into the power production forecast, and explains how the power production forecast is used to reduce regulation reserve requirements; and
  • Explains how forecasting results will be shared with VER generators.

The Final Rule clarifies that transmission customers are responsible for the accuracy of their own transmission schedules, and declines to require that transmission customers submit transmission schedules according to the transmission provider’s centralized forecast.

The Final Rule requires compliance within twelve months of the Rule’s effective date.


The limited scope of the Final Rule and the suggestions for (1) negotiations between transmission providers and VER owners about the scope of data requirements and (2) the factors a transmission provider must consider in designing integration charges or different scheduling regimes, appear to reflect FERC’s recognition that it is premature to impose too many rigid rules because the technology and the terms of VER integration are still works in progress.  Apart from the Final Rule’s 15-minute scheduling and VER operator data reporting requirements, the Final Rule encourages a continuing dialogue within the industry, and between FERC and the industry, about the terms and conditions for optimizing the integration of VERs.

The addition of intra-hour scheduling to the pro forma OATT should facilitate more accurate commitment of VERs, and is thus a measured step by FERC toward increased penetration of renewable energy sources.  This concept already is inherent in the scheduling provisions in several of the organized markets.  Nevertheless, it is not certain how many customers will schedule service on this basis.  Transmission providers may encounter operational concerns. 

Generators will have to provide more granular information to their respective transmission providers regarding weather forecasts and operational status projections.  As noted above, this will allow transmission providers to more accurately project power output and adjust reserves accordingly.  Although it remains to be seen how much this will reduce generator charges, the new scheduling and forecasting requirements may lead to the development of new ancillary services and energy storage products that could impact the way in which transmission providers provide such services and cost recovery of existing assets.

With regard to cost recovery of generator regulation service, although the Final Rule maintains FERC’s case-by-case approach to cost recovery, FERC has outlined discrete principles that have yet to be fleshed out.  FERC may view the reforms it proposed in its Notice of Proposed Rulemaking on Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies as an alternate route to address this issue, ease burdens on third-party ancillary service providers, and promote efficient provision of imbalance and regulation services. 


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

Gabe Tabak is a summer associate with the firm. 

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