On June 22, 2012, FERC issued its long-awaited rule to encourage the integration of Variable Energy Resources1 (VERs) onto the grid, Integration of Variable Energy Resources (Order No. 746). The concepts ultimately approved in Order No. 746 were, for the most part, strongly supported by the renewable energy industry, which argued that reform was needed because the existing market rules were designed to reflect the characteristics of more traditional generating resources, such as coal, natural gas and nuclear generation, and created market and operational barriers to VER integration.
However, traditional public utilities tended to oppose the changes, questioning, inter alia, whether FERC had articulated a sufficient basis (1) to require the changes under the Federal Power Act (FPA) and (2) to find that the current rules were “unduly discriminatory,” one of the legal standards that FERC relies on under the FPA. Ultimately, FERC held, “in light of the increasing deployment of VERs on the nation’s transmission system, the reforms adopted herein are necessary to correct operational practices that can limit the cost-effective integration of VERs into the transmission system consistent with open access principles.”
Order No. 746 is expected to be subject to judicial review.2
Intra-hour Scheduling
Scheduling under most Open Access Transmission Tariffs (OATTs) is currently done on an hourly basis, which leaves VERs exposed to OATT “Schedule 9” imbalance service charges, i.e., charges assessed to pay for the energy service the transmission provider must offer to account for deviations between a transmission customer’s scheduled delivery of energy from a generator and the amount of energy actually generated.
Order No. 746 requires Transmission Providers to amend their OATTs to provide for, at a minimum, 15-minute scheduling to reflect changes in generation output. FERC noted that many types of entities, not only VERs, may benefit from the availability of intra-hour scheduling. Every transmission customer will have the ability to adjust its schedule at 15-minute intervals to reflect changing conditions. This includes, for example, transmission customers that experience a within-hour forced outage, or transmission customers taking delivery from energy constrained resources (such as flow-limited hydro-electric generators, emission-limited thermal generators, and energy storage resources), even if using point-to-point transmission internal to the system.3 FERC noted that there was broad support for the concept of intra-hour scheduling, but disagreement over the appropriate interval. FERC also noted that, over time, implementation of intra-hour scheduling should allow public utility transmission providers to rely more on planned scheduling and dispatch procedures, and less on reserves, to maintain overall system balance.
The implementation of 15-minute scheduling intervals was expected. Unexpected was FERC’s decision to grant public utility transmission providers the ability to use alternative proposals that are provably consistent with or superior to the 15-minute, intra-hour scheduling requirement. In order to obtain permission for an alternative scheduling protocol, a public utility transmission provider will be required to show how its proposal provides equivalent or greater opportunities for transmission customers to mitigate Schedule 9 generator imbalance charges, and for the public utility transmission provider, to lower its reserve-related costs.4
Meteorological and Forced Outage Data Required
FERC is amending the pro forma Large Generator Interconnection Agreement (LGIA) to add a new Article 8.4 and to revise Appendix C, to require VER interconnection customers to provide certain types of meteorological and forced outage data to the public utility transmission provider for power production forecasting.
The reporting requirement will not apply to the following:
- VERs with existing LGIAs, which will not be amended to include the new reporting requirements
- VERs under 20 MWs that are subject to the pro forma Small Generator Interconnection Agreement (SGIA)
- VERs that are Qualifying Facilities and whose total output is purchased by the interconnected electricity utility (in such a case, the relevant state authority exercises authority over the interconnection and allocation of interconnection costs)
Power production forecasts can provide public utility transmission providers with advanced knowledge of system conditions needed to manage the variability of VER generation through the unit commitment and dispatch process, rather than through the deployment of reserve service, such as regulation reserves, which can be more expensive.
Implementation of these reporting requirements – commensurate with the power production forecasting employed by the public utility transmission provider – is intended to allow for more accurate commitment or de-commitment of resources providing reserves, which should ensure that reserve-related charges imposed on customers remain just and reasonable. By linking the requirement to provide meteorological and forced outage data to the use of these data by the public utility transmission provider in power production forecasting to manage reserve commitments, FERC sought to minimize opportunities for undue discrimination, as well as needless burden on interconnection customers.
With respect to the specific data to be provided by VERs, Order No. 746 gives public utility transmission providers flexibility in identifying the specific meteorological and forced outage data to be reported, but certain categories of data will be listed in the amendments to the pro forma LGIA. Thus:
- A wind interconnection customer must provide, at a minimum, site-specific meteorological data, including temperature, wind speed, wind direction, and atmospheric pressure.
- A solar interconnection customer must provide, at a minimum, site-specific meteorological data, including temperature, atmospheric pressure, and irradiance.
The exact specifications of data to be provided by the interconnection customer will remain subject to negotiation between the parties, which must take into account the size and configuration of the VER; its characteristics and location; and its importance in maintaining generation resource adequacy and transmission system reliability in its area. The required data may also include additional meteorological data commensurate with the power production forecasting employed by the public utility transmission provider. As with other data reporting requirements, the public utility transmission provider may file an unexecuted LGIA pursuant to FPA section 205 seeking to demonstrate the necessity of requests for additional information if the parties cannot reach mutual agreement as to the specifications of data to be provided.
No Set Approach for Generator Regulation Service
FERC declined to modify the pro forma OATT to include a new Schedule 10 governing generator regulation service as it originally proposed. FERC intended for the proposed Schedule 10 to provide clarity to public utility transmission providers and transmission customers by establishing a generic approach to the provision of generator regulation service. Numerous commenters urged FERC to forgo a standardized approach to generator regulation service on the grounds that flexibility was necessary in the design of capacity services needed to efficiently integrate VERs into the transmission system. FERC ultimately agreed, and decided that it would continue to evaluate proposed generator regulation service charges on a case-by-case basis.
FERC did, however, provide some general guidance to assist public utility transmission providers and their customers in the development and evaluation of proposals related to recovering the costs of regulation reserves associated with VER integration, including, inter alia:
- Public utility transmission providers that choose to propose a rate schedule for generator regulation service may include opportunity costs for generator regulation service in certain circumstances.
- With respect to the appropriate design of the volumetric component of Schedule 10 (which would have allowed transmission providers to require different transmission customers, or generator classes, to purchase or otherwise account for different quantities of regulation reserves based on cost causation principles), distinctions among classes must be related to operational differences among resources.
- To the extent a public utility transmission provider proposes to differentiate among customers (or customer classes) in determining their relative regulating reserve responsibilities, the public utility transmission provider must demonstrate that the overall quantity of regulating reserve it requires of its transmission customers accounts for diversity benefits among all resources and loads, and the allocations to individual customers (or customer classes) of their proportionate share, is based on the operational characteristics of such customers (or customer classes).
Order No. 746 becomes final 60 days after its publication in the Federal Register.
1 Variable Energy Resources are defined as ”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.” FERC specifically declined to limit the VER definition to exclude run-of-river hydro, tidal, or new and emerging VER technologies. (Order No. 746 at PP 210, 213)
2 Commissioner LeFleur dissented on a narrow point of compliance with respect to the rule. She argued that the rule only allows parties to demonstrate compliance through incremental reforms beyond those already underway, without any explanation of why the ongoing efforts are insufficient.
3 FERC noted that Entergy voluntarily adopted intra-hour transmission scheduling without the presence of substantial VERs in an effort to manage fluctuations in output from qualifying facilities on its system. (Order No. 746 at P 94)
4 (Order No. 746, LaFleur dissent)
Client Alert 2012-146