Stoel Rives Energy Regulation Report
REGULATORY UPDATES BELOW:
FERC Opens Rulemaking on Intra-Hour Scheduling, Forecasting Requirements, and Integration Services for Variable Energy Resources
- FERC issues a Notice of Proposed Rulemaking on Variable Energy Resources.
- FERC extends the comment deadline in the Milford and Cedar Creek appeals of Transmission Owner and Transmission Operator registration.
- FERC denies a petition by Puget Sound Energy to protect priority rights to interconnection capacity.
The Federal Energy Regulatory Commission (FERC) has taken yet another step toward amending transmission practices that unduly discriminate against variable energy resources (VERs) such as wind and solar generators. On November 18, 2010, FERC issued proposed changes to the pro forma open access transmission tariff (OATT) and large generator interconnection agreement that intend to reduce the costs of integrating large amounts of VERs on the transmission system. FERC proposes to (a) require transmission providers to offer transmission service that can be scheduled on 15-minute intervals, (b) require interconnection customers that operate VERs to provide forecasting and meteorological data to transmission providers that are deploying and/or developing power production forecasting processes, and (c) add a new rate schedule – Schedule 10 – for generation regulation (i.e., integration) services. The proposed rule is the first to come out of the Notice of Inquiry on VERs that FERC issued in January 2010.
Transmission Providers Must Give Customers an Option to Schedule Transmission Service at 15-Minute Intervals.
FERC proposes that transmission providers must give customers the option to schedule transmission service at 15-minute intervals. In doing so, FERC proposes that 15-minute periods will become the new default scheduling interval, which will allow for scheduling consistency across multiple transmission systems. Currently, transmission is scheduled on an hourly basis with schedules being generated 20-30 minutes before the hour. Schedules may thus be 90 minutes old by the end of the operating hour, causing transmission providers to rely heavily on reserves to make up for imbalances in the energy output from VERs. FERC noted the current process is unduly discriminatory and results in inefficient use of transmission and generation resources to the detriment of consumers. Under the proposed rule, however, all transmission customers will be given the option to schedule transmission service on shorter intervals, thereby allowing transmission providers to rely more on accurate schedules (and less on reserves) to keep the transmission system in balance and offer greater efficiency in dispatching all resources. FERC proposes that the costs of implementing intra-hour scheduling will be recovered through Schedule 1 (Scheduling, System Control and Dispatch Service) to the OATT.
Transmission Providers Who Charge for Generation Integration Services Must Implement Power Production Forecasting.
FERC proposes that all transmission providers who charge for generation regulation service under the newly proposed Schedule 10 must use power production forecasting to enhance their transmission system's flexibility and, ultimately, reduce the reserves that transmission providers must hold to maintain system balance. FERC believes that power production forecasting can improve the efficiency of reliability unit commitments (using day-ahead and intra-day forecasting timeframes) and dispatch instructions (using hour-ahead or shorter forecasting timeframes), and provide for the greater predictability of VER ramping events. To facilitate the implementation of power production forecasting, FERC is proposing to reform the pro forma interconnection agreement to require VERs to supply meteorological and operational data to their transmission providers on intervals at or near real time. Further, FERC proposes that transmission providers and interconnection customers will negotiate resource-specific forecasting requirements into interconnection agreements, taking into account the size and configuration of individual VER facilities, in addition to their characteristics, location, and impact on resource adequacy and reliability. Also, in order to improve the accuracy of power production forecasts, FERC proposes to require VER interconnection customers to report to their transmission providers any forced outages that reduce the generating capability of a resource by 1 MW or more for 15 minutes or more.
FERC seeks comment on the type of forecasting and meteorological data to be required of VER interconnection customers. FERC also seeks comment on its proposed definition of VERs as "an energy resource 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." The proposed changes would be limited to VERs larger than 20 MW, although FERC seeks comment on whether to apply the new rules to VERs 20 MW and smaller.
FERC Proposes to Add Schedule 10, Generator Regulation Service and Frequency Response, to the OATT.
FERC proposes to add a new rate schedule to the pro forma OATT through which transmission providers can recover the costs of holding the reserves capacity needed to manage the variability of generation resources serving load within a transmission provider's balancing authority area or exporting to load elsewhere. The new Schedule 10 would be modeled on Schedule 3 (Regulation and Frequency Response) and would require transmission providers to offer the service, to the extent feasible from its own or available resources, to customers taking transmission service from a generator located within the transmission provider's balancing authority area. A transmission customer subject to the rate schedule will be required to take service or demonstrate that it has satisfied the regulation obligation through dynamic scheduling or self-supply from generation or non-generation resources. Transmission providers will not be allowed to charge under both Schedule 3 and Schedule 10 for the same transaction.
Like Schedule 3, Schedule 10 will consist of two components: a per-unit rate and a volumetric component. FERC proposes that it is reasonable for transmission providers to use the same per-unit rate currently established in Schedule 3 when charging for service under Schedule 10. Where a transmission provider seeks to apply a different rate under Schedule 10, it would have to justify the cost differences to FERC. With respect to the volumetric component, FERC stated that different types of resources impose different levels of variability. Thus, each transmission provider will be required to propose a method for apportioning the volumes of regulation reserves based on the characteristics of its individual system. However, a transmission provider may not assign different volumetric requirements to different generation resources without demonstrating that the differing volumes are commensurate with the actual variability exhibited by VERs on the system and implementing intra-hourly scheduling and power production forecasting.
Comments on the Notice of Proposed Rulemaking are due by 60 days after publication in the Federal Register. If you have questions about the Notice of Proposed Rulemaking, or you seek assistance with crafting and filing comments, please contact one of the attorneys listed below.
FERC Extends Comment Period in Wind Farms' Appeal of NERC Decision to Uphold Registration as Transmission Owners/Operators
FERC has extended the comment deadline in Cedar Creek Wind Energy (Cedar Creek) and Milford Wind Corridor's (Milford) appeal of a decision by the North American Electric Reliability Corporation (NERC) that affirmed the Western Electricity Coordinating Council's (WECC) registration of the two wind farms as Transmission Owners (TO) and Transmission Operators (TOP). Another generator was so registered by WECC two years ago and, on appeal, estimated that the cost of complying with the TO/TOP reliability standards would be approximately $1 million per year. (That generator lost its appeal.)
In October, NERC concluded that Cedar Creek (which owns 72 miles of a sole-use 76-mile, 230 kV interconnection line that serves its 300 MW wind farm) and Milford (which owns a sole-use 88-mile, 345 kV interconnection line that serves its 203.5 MW wind farm) were appropriately registered for TO/TOP reliability functions. NERC reasoned that because the interconnection lines connect generating facilities that are registered for Generator Owner and Generator Operator functions to the transmission facilities that fall under a TO/TOP registration, the interconnection lines are material to the reliability of the bulk power system.
Many generation developers, owners, and operators should be aware of NERC's decision, and the subsequent appeal, because such reasoning, if upheld by FERC, would support a TO/TOP registration for any generator sized 20 MVA (single unit) or 75 MVA (multiple units) or greater that interconnects at a voltage of 100 kV or above.
Comments are due in this docket by December 7, 2010. If you have questions about reliability standards or NERC's ruling, or you are concerned about NERC's ruling and would like assistance in filing comments, please contact one of the attorneys listed below.
FERC Denies Puget Sound Energy Request to Protect Interconnection Capacity Rights
On November 18, 2010, FERC denied a request from Puget Sound Energy (Puget) to establish its priority rights to interconnection capacity. In June of this year, Puget filed a petition for declaratory order in which it sought to protect its rights to 1,250 MW of capacity that would serve Phases I through III of the Lower Snake River Project wind farm. Phases IV and V of the Lower Snake River Project would use approximately 580 MW of the lead line's capacity in the future, but the phases would require an additional 28 miles of new conductor. Puget nevertheless sought to protect the lead line's full 1,250 MW of capacity. The lead line is designed to tie the wind farm to the Bonneville Power Administration transmission system, and would be used to transmit the wind farm's power to Puget's native load.
In its filing, Puget asserted that by eliminating the need for later upgrades, constructing the entire interconnection capacity needed by the Lower Snake River Project is environmentally and economically friendly. Also in light of the difficulties in permitting and financing a large wind project, Puget asserted that other wind developers should not permitted to infringe on its rights to the interconnection capacity by its full project. In support of its petition, Puget cited FERC's orders in Milford Wind Corridor and Aero Energy, where FERC granted certain developers priority to interconnection capacity after making the necessary showings.
FERC concluded that Milford and related rulings do not apply to Puget's circumstances, and denied the petition. Instead, FERC ruled that, because Puget is serving its native load and has an OATT on file with FERC, the capacity over its generator lead lines must be governed by the conditions in the OATT. This conclusion was in spite of the fact that Puget transmission function has no part in developing the Lower Snake River Project. As a result of the ruling, Puget may only reserve existing transmission capacity needed for native load growth based on a reasonable forecast over Puget's planning horizon. To the extent such capacity is reserved, the capacity must be made available to open access customers until it is needed. Furthermore, to the extent that any capacity on the lead line is not needed to serve native load growth, Puget must make the capacity available to other transmission customers.
If you have any questions about this order or about protecting your interconnection capacity rights, please contact one of the following attorneys.
Marcus Wood at (503) 294-9434 or firstname.lastname@example.org
Jennifer Martin at (503) 294-9852 or email@example.com
Jason Johns at (503) 294-9618 or firstname.lastname@example.org
Sara Bergan at (503) 294-9336 or email@example.com