Daily Rules, Proposed Rules, and Notices of the Federal Government
1. In this Notice of Proposed Rulemaking (Proposed Rule), the Federal Energy Regulatory Commission (Commission) proposes reforms to the
2. In Order No. 890, the Commission made several reforms to the
3. In this Proposed Rule, the Commission proposes the following three reforms: (1) Amend the
4. Specifically, the Commission preliminarily finds that requiring transmission customers to adhere to hourly schedules may be unduly discriminatory and result in the inefficient use of transmission and generation resources to the detriment of consumers. The Commission also preliminarily finds that a lack of VER power production forecasts may unnecessarily increase the volume of regulation reserves deployed by a public utility transmission provider, resulting in rates that are unjust and unreasonable, and that a public utility transmission provider currently lacks the means by which to require VERs to provide it with basic information on meteorological and operational conditions which can be used to develop VER power production forecasts. Finally, although the Commission contemplated a case-by-case approach to generator regulation service in Order No. 890,
5. Taken together, these proposed reforms mean: VERs and other resources will be able to adjust schedules within the operating hour, allowing public utility transmission providers to commit fewer generation and non-generation resources to provide reserves; public utility transmission providers will have better meteorological and operational information from interconnection customers whose generating facilities are VERs and will be able to use this information to develop power production forecasts for use in operating their systems, thus mitigating the volume of regulation reserves they deploy; and public utility transmission providers will have a generic schedule from which to recover the costs of providing generator regulation service, and customers and other market participants will know the cost of such service. These proposed reforms are intended to ensure that the requirements set forth in the
6. In 1996, the Commission issued Order No. 888, which found that it was in the economic interest of public utility transmission providers to deny transmission service or to offer transmission service on a basis that is inferior to that which they provide to themselves.
7. The Commission later turned its attention to the process by which large generators interconnect with the interstate transmission system. In Order No. 2003, the Commission concluded
8. In Order No. 2003-A, the Commission explained that the interconnection requirements adopted in Order No. 2003 were based on the needs of traditional synchronous generators and that a different approach may be appropriate for generators relying on newer technology.
9. More recently, in recognition of the evolving energy industry and in a further effort to remedy the potential for undue discrimination, the Commission revised and updated the
10. As these and other reforms illustrate, the Commission routinely evaluates the effectiveness of its regulations and policies in light of changing industry conditions. Consistent with this practice, the Commission issued the Integrating VERs NOI on January 21, 2010 to better understand the challenges associated with the large-scale integration of VERs on the interstate transmission system and the extent to which existing operational practices may be imposing barriers to their integration.
11. The response from commenters was significant, with more than 135 entities submitting comments that responded to some or all of the questions posed by the Commission.
12. The Commission preliminarily finds that the package of reforms proposed herein is needed to protect against unjust and unreasonable rates, terms, and conditions and undue discrimination in the provision of Commission-jurisdictional services. Specifically, the Commission is proposing to reform the
13. As noted in the Integrating VERs NOI, the composition of the electric generation portfolio is changing. VERs are making up an increasing percentage of new generating capacity being brought on line—in 2009, new wind generating capacity rose to 9,994 MW, or 39 percent of all newly installed generating capacity, bringing total wind generating capacity to more than 35,000 MW.
14. The Commission expects the number of VERs, both in real numbers and as a percentage of total generation capacity, to continue to grow. Indicators of this anticipated growth are suggested by the significant number of public policies, both at the state and federal levels, encouraging the development of VERs. In the Integrating VERs NOI, the Commission noted that as of December 2009, 30 states and the District of Columbia had a renewable portfolio standard.
15. The Commission has recognized this policy development, not only in this proceeding, but also in the Transmission Planning and Cost Allocation Proposed Rule, observing that “state policies to promote increased reliance on renewable energy resources, such as the renewable portfolio standard measures discussed above, accentuate the need for transmission to deliver electricity from location-constrained renewable energy resources to load centers.”
16. As the number of VERs has increased, the Commission has received a variety of proposals that seek variations from the
17. In light of these filings, comments, and the increasing deployment of VERs on the nation's transmission system, the Commission has identified reforms that it preliminarily finds would eliminate operational procedures that have the
18. The Commission is aware that, in many instances, issues associated with VER integration are highly technical in nature and can vary significantly from one region to the next. The Commission is also cognizant of and supports ongoing industry initiatives dedicated to crafting regional solutions to the challenges associated with VER integration. Such regional efforts include the work being conducted by the North American Electric Reliability Corporation (NERC) through the Integration of Variable Generation Task Force
19. The Commission is proposing three reforms that, taken together, are designed to address issues confronting public utility transmission providers and VERs and to allow for the more efficient utilization of transmission and generation resources to the benefit of all customers. First, the Commission proposes to provide the transmission customer with the option of using more frequent transmission scheduling intervals within each operating hour, at 15-minute intervals, so that they may adjust their transmission schedules to reflect, in advance of real-time, more accurate power production forecasts, load profiles, and other changing system conditions. At the same time, this proposed reform will enable public utility transmission providers and other entities to manage the system's variability more effectively and, over time, rely less on ancillary services and more on the flexibility of generation and non-generation resources.
20. Second, the Commission proposes to require public utility transmission providers to amend their
21. Third, the Commission proposes to add a generic ancillary service rate schedule to the
22. Additionally, the Commission is proposing guidelines under which public utility transmission providers may assess generator regulation reserve charges to transmission customers. Such charges must be established based on traditional cost causation principles. To the extent a public utility transmission provider proposes to require transmission customers who are delivering energy from VERs to purchase, or otherwise account for, a different volume of generator regulation reserves than it proposes to charge transmission customers delivering energy from other generating resources, such differing volumes must be shown to be commensurate with the variability that VERs exhibit on the transmission provider's system. Furthermore, the public utility transmission provider must show that it has adopted measures to mitigate the total amount of regulation reserve necessary to manage the variability through the implementation of VER power production forecasting and intra-hourly scheduling. This mitigation requirement will help to ensure that the rates for this service are just and reasonable.
23. Through these three proposals, the Commission seeks to reform operational protocols that present barriers to the integration of VERs and to ensure the cost of integrating new resources, such as VERs, are not unnecessarily inflated by inappropriate systems and processes. While the proposed reforms focus on discrete operational protocols, they are integrally related and should be understood as complementary parts of a package. The Commission believes this set of reforms will help to level the playing field for all types of resources, provide much-needed clarification as to the roles and responsibilities of public utility transmission providers and transmission customers, and bring greater transparency and efficiency to existing system operations. As described in more detail below, the Commission believes that these proposed rules are necessary to remedy undue discrimination in existing transmission system operations and to ensure that rates for Commission-jurisdictional services are just and reasonable.
24. As should be clear from the scope of this Proposed Rule, the Commission is not proposing to address the additional issues identified in the Integrating VERs NOI at this time. Upon review of the comments, the Commission believes that further study of many issues identified in the Integrating VERs NOI is required. In addition, a number of parties are actively developing solutions to address issues raised in the Integrating VERs NOI.
25. Outside of regions that have an RTO or ISO, resources typically
26. The Commission further explained that because transmission schedules are typically set 20-30 minutes ahead of the hour, the forecast of a VER's output (upon which its schedule is based) may be 90 minutes old by the end of the operating hour.
27. Therefore, the Commission sought to explore whether the retention of existing transmission scheduling practices had caused the rates for reserves to become unjust and unreasonable by inhibiting the ability of VERs to establish operationally-viable schedules and preventing public utility transmission providers from utilizing the flexibility of their systems. More specifically, the Commission sought to explore whether greater transmission scheduling flexibility, such as intra-hour scheduling or other improvements in the scheduling procedures, might offer the potential for greater efficiency in dispatching all resources. For instance, the Commission noted the potential for more efficient dispatch if the magnitude of schedule deviations could be reduced, better anticipated, and/or planned for more precisely.
28. Most commenters recognize the benefits and support the implementation of some form of intra-hour transmission scheduling. AWEA states that shorter scheduling intervals will allow generators to provide inexpensively much of the flexibility that is currently being provided by expensive regulation reserves.
29. WECC explains that shorter scheduling intervals allow system operators to manage the integration of VERs more efficiently, because they permit the use of forecasts that are closer to the operating time frame, and are therefore more accurate.
30. AWEA argues that hourly scheduling practices have a much greater negative impact on VERs than on traditional dispatchable resources and that it is within the Commission's statutory duty to address these issues of discrimination.
31. Many commenters, however, seek the flexibility to develop regional solutions without a Commission mandate that they be required to do so. The common reason given for this view is that each region has a unique mix of conventional generation resources and VERs, and each region should be
32. Additionally, several of the commenters that oppose a Commission mandate to implement intra-hour scheduling cite reform efforts that are already underway. For example, the Joint Initiative describes its development of model intra-hour transmission purchase and scheduling business practices in the Western Interconnection.
33. Commenters generally recognize that the implementation process is not without some costs. AWEA states that the cost of transitioning to intra-hourly dispatch is quite modest and the bulk of these costs are up-front expenditures while the benefits of making the transition will be realized in perpetuity.
34. Entergy states that it moved from hourly scheduling to twenty-minute anytime-scheduling several years ago.
35. Smaller public utility transmission providers highlight challenges with respect to their size and explain that the implementation of intra-hour scheduling may be infeasible for certain entities. NRECA indicates that for smaller systems, implementation of intra-hour scheduling would be a significant additional burden and could require substantial costs in software modification.
36. Finally, some commenters oppose the implementation of intra-hour scheduling for their regions regardless of cost or whether the Commission allows for regional differences. Generally, these commenters base their objections on two grounds. First, commenters under the impression that the intra-hour scheduling would be available only to transmission customers using VERs argue that it would be unfair to afford scheduling opportunities to one class of transmission customers and not others, such as those utilizing conventional resources. Southern argues that there should not be any unique or special scheduling protocols applicable to only certain types of generation.
37. The Commission preliminarily finds that hourly transmission scheduling protocols are no longer just and reasonable and may be unduly discriminatory as the default scheduling time periods required by the
38. As explained above, hourly transmission scheduling protocols were developed at a time when virtually all generation on th