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Daily Rules, Proposed Rules, and Notices of the Federal Government

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-11-000]

Integration of Variable Energy Resources

AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of proposed rulemaking.
SUMMARY: In this Notice of Proposed Rulemaking, the Federal Energy Regulatory Commission proposes to reform thepro formaOpen Access Transmission Tariff to remove unduly discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional services. Accordingly, the Proposed Rule would: require public utility transmission providers to offer intra-hourly transmission scheduling; incorporate provisions into thepro formaLarge Generator Interconnection Agreement requiring interconnection customers whose generating facilities are variable energy resources to provide meteorological and operational data to public utility transmission providers for the purpose of power production forecasting; and add a generic ancillary service rate schedule through which public utility transmission providers will offer regulation service to transmission customers delivering energy from a generator located within the transmission provider's balancing authority area. The proposed reforms will remove barriers to the integration of variable energy resources.
November 18, 2010.
DATES: Comments are due January 31, 2011.
ADDRESSES: *Agency Web site:Documents created electronically using word processing software should be filed in native applications or print-to-PDF format, and not in a scanned format, athttp://www.ferc.gov/docs-filing/efiling.asp.

*Mail/Hand Delivery:Commenters unable to file comments electronically must mail or hand deliver an original copy of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street, NE., Washington, DC 20426. These requirements can be found on the Commission's Web site,see, e.g.,the "Quick Reference Guide for Paper Submissions," available athttp://www.ferc.gov/docs-filing/efiling.asp,or via phone from FERC Online Support at 202-502-6652 or toll-free at 1-866-208-3676.

FOR FURTHER INFORMATION CONTACT:

Mk Shean (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6792,Mk.Shean@ferc.gov; Andrea Hilliard (Legal Information), Office of General Counsel--Energy Markets, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-8288,Andrea.Hilliard@ferc.gov.

SUPPLEMENTARY INFORMATION: Table of Contents Paragraph/
  • Nos.
  • I. Introduction 1 II. Background 6 III. The Need for Reform 12 IV. Summary of Proposed Reforms 19 V. Proposed Reforms 25 A. Intra-hourly Scheduling 25 B. Power Production Forecasting and Data Reporting 45 C. Generator Regulation Service-Capacity 66 VI. Compliance Filings 101 VII. Information Collection Statement 108 VIII. Environmental Analysis 112 IX. Regulatory Flexibility Act Analysis 113 X. Comment Procedures 115 XI. Document Availability 119 Regulatory Text Appendix A: List of Short Names of Commenters on the Federal Energy Regulatory Commission's Notice of Inquiry on Integration of Variable Energy Resources—Docket No. RM10-11-000, January 2010 Appendix B: Proposed inserts to thePro FormaOpen Access Transmission Tariff Appendix C: Proposed inserts to thePro FormaLarge Generator Interconnection Agreement
    I. Introduction

    1. In this Notice of Proposed Rulemaking (Proposed Rule), the Federal Energy Regulatory Commission (Commission) proposes reforms to thepro formaOpen Access Transmission Tariff (OATT) that derive from the Integration of Variable Energy Resources Notice of Inquiry.1 The Commission initiated that inquiry to obtain information on barriers to the integration of variable energy resources (VER)2 and on the current state of VER integration in various regions of the country. Not unexpectedly, commenters indicate that VER presence is not uniform throughout the country. Commenters also describe their experiences integrating VERs and the on-going industry efforts designed to address issues posed by increasing numbers of VERs. Many of these industry efforts are significant in scope and have the potential to address issues confronting regions where largeconcentrations of VERs are located.3 Accordingly, in the Proposed Rule, the Commission has decided to propose a limited set of reforms to existing operational procedures that we preliminarily find to be unduly discriminatory and leading to unjust and unreasonable rates for transmission service. Specifically, the Proposed Rule addresses transmission scheduling practices, VER power production forecasts, and the recovery of capacity charges associated with generator imbalance service (i.e.,generator regulation service).

    1 Integration of Variable Energy Resources,130 FERC ¶ 61,053 (2010) (Integrating VERs NOI).

    2For the purpose of this proceeding, the term variable energy resource (VER) refers to an electric generating facility 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. This includes, for example, wind, solar thermal and photovoltaic, and hydrokinetic generating facilities.

    3 See, e.g.,Joint Initiative at 1-12 (describing collaborative efforts in the Western Interconnection for high-value and cost-effective regional products involving increased coordination among different transmission providers), SMUD at 8-12 (describing SMUD's participation in regional efforts in California and the Northwest), ISO/RTO Council at 12-18 (discussing ISO/RTO efforts to develop and incorporate VER forecasting into their system operations).

    2. In Order No. 890, the Commission made several reforms to thepro formaOATT, recognizing that the mix of generation resources on the system was changing and that not all generation resources were similarly situated.4 The Commission recognized that intermittent resources, such as wind power, have a limited ability to control their output, and that this limitation supports tailoring certain requirements to the special circumstances presented by this type of resource.5 Similarly, the Commission preliminarily finds that the practice of hourly scheduling, the lack of VER power production forecasting, and the lack of a clear mechanism to recover the cost of providing generator regulation service may be contributing to undue discrimination and unjust and unreasonable rates in light of the entry and increasing presence of VERs on the transmission grid.

    4 Preventing Undue Discrimination and Preference in Transmission Service,Order No. 890, FERC Stats. & Regs. ¶ 31,241, at P 5,order on reh'g,Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007),order on reh'g,Order No. 890-B, 123 FERC ¶ 61,299 (2008),order on reh'g,Order No. 890-C, 126 FERC ¶ 61,228,order on clarification,Order No. 890-D, 129 FERC ¶ 61,126 (2009).

    5Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 663 (requiring that generator imbalance provisions account for the special circumstances presented by intermittent generators).

    3. In this Proposed Rule, the Commission proposes the following three reforms: (1) Amend thepro formaOATT to require intra-hourly transmission scheduling; (2) amend thepro formaLarge Generator Interconnection Agreement to incorporate provisions requiring interconnection customers whose generating facilities are VERs to provide meteorological and operational data to public utility transmission providers for the purpose of improved power production forecasting; and (3) amend thepro formaOATT to add a generic ancillary service rate schedule, Schedule 10—Generator Regulation and Frequency Response Service, in which public utility transmission providers will offer to provide regulation service for transmission customers using transmission service to deliver energy from a generator located within a public utility transmission provider's balancing authority area. The Commission recognizes that as the number of VERs increases, public utility transmission providers and their customers will need processes and tools to manage the changing nature of generation resources on the transmission grid. As such, the Commission believes the reforms proposed herein will address some of the barriers to the integration of VERs by remedying operational and other challenges that may be causing undue discrimination and increased costs ultimately borne by consumers.

    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. 890,6 the increased interest as evidenced by commenters and the number of Commission filings related to this service has led us to consider a generic approach to the provision of generator regulation service, such as the one proposed here.

    6Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 690.

    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 thepro formaOATT result in the provision of Commission-jurisdictional services at rates that are just and reasonable, and not unduly discriminatory or preferential, consistent with the Commission's responsibilities under sections 205 and 206 of the Federal Power Act (FPA).7

    716 U.S.C. 824d, 824e.

    II. Background

    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.8 Concluding that unduly discriminatory and anticompetitive practices existed in the electric industry and that, absent Commission action, such practices would increase as competitive pressures in the industry grew, the Commission in Order No. 888 required all public utility transmission providers that own, control, or operate transmission facilities used in interstate commerce to have on file an open access, non-discriminatory transmission tariff that contains minimum terms and conditions of non-discriminatory service. As relevant here, thepro formaOATT contains terms for scheduling transmission service and the provision of ancillary services.

    8 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,682 (1996),order on reh'g,Order No. 888-A, FERC Stats. & Regs. ¶ 31,048,order on reh'g,Order No. 888-B, 81 FERC ¶ 61,248 (1997),order on reh'g,Order No. 888-C, 82 FERC ¶ 61,046 (1998),aff'd in relevant part sub nom. Transmission Access Policy Study Groupv.FERC,225 F.3d 667 (D.C. Cir. 2000),aff'd sub nom. New Yorkv.FERC,535 U.S. 1 (2002).

    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 concludedthat there was a pressing need for a single set of procedures and a single, uniformly applicable interconnection agreement for large generator interconnections.9 Accordingly, the Commission adopted standard procedures (the Large Generator Interconnection Procedures or LGIP) and a standard agreement (the Large Generator Interconnection Agreement or LGIA) for the interconnection of generation resources greater than 20 MW.10 These reforms were designed to minimize opportunities for undue discrimination and expedite the development of new generation, while protecting reliability and ensuring that rates are just and reasonable.11

    9 Standardization of Generator Interconnection Agreements and Procedures,Order No. 2003, FERC Stats. & Regs. ¶ 31,146, at P 11 (2003),order on reh'g,Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160,order on reh'g,Order No. 2003-B, FERC Stats. & Regs. ¶ 31,171 (2004),order on reh'g,Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005),aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rsv.FERC,475 F.3d 1277 (DC Cir. 2007).

    10 Id.

    11 Id.

    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.12 The Commission therefore exempted wind resources from certain sections of the LGIA and added Appendix G to the LGIA, as a placeholder for the inclusion of interconnection standards specific to newer technologies.13 Subsequently, in Orders Nos. 661 and 661-A, the Commission adopted a package of interconnection standards applicable to large wind generators for inclusion in Appendix G of the LGIA.14

    12Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160 at P 407 n.85.

    13 Id.

    14 Interconnection for Wind Energy,Order No. 661, FERC Stats. & Regs. ¶ 31,186 (2005),order on reh'g,Order No. 661-A, FERC Stats. & Regs. ¶ 31,198 (2005).

    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 thepro formaOATT in Order No. 890.15 Among other things, the Commission adopted a set of transmission planning principles,16 created a newpro formaancillary service schedule designed to address energy imbalances caused by generators,17 and instituted a new conditional firm transmission product.18

    15Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh'g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261,order on reh'g,Order No. 890-B, 123 FERC ¶ 61,299,order on reh'g,Order No. 890-C, 126 FERC ¶ 61,228,order on clarification,Order No. 890-D, 129 FERC ¶ 61,126.

    16Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 435-43.

    17 Id.P 663-72.

    18 Id.P 911-15.

    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.19 The Commission explained that the changing characteristics of the nation's generation portfolio compelled a fresh look at existing policies and practices.20 Therefore, in the Integrating VERs NOI, the Commission sought comments on the following subject areas: (1) Power production forecasting, including specific forecasting tools and data and reporting requirements; (2) scheduling practices, flexibility, and incentives for accurate scheduling of VERs; (3) forward market structure and reliability commitment processes; (4) balancing authority area coordination and/or consolidation; (5) suitability of reserve products and reforms necessary to encourage the efficient use of reserve products; (6) capacity market reforms; and (7) redispatch and curtailment practices necessary to accommodate VERs in real time.21

    19Integrating VERs NOI, 130 FERC ¶ 61,053 at P 9.

    20 Id.

    21 Id.P 12.

    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.22 A number of commenters, especially from the VER industry, argue that there is a clear need for the Commission to undertake basic reforms, and they urge the Commission to do so.23 At the same time, a common theme expressed by a number of commenters is that different parts of the country face different challenges associated with the integration of VERs.24 For example, commenters in the Northwest tend to focus on the difficulties posed by the deployment of wind resources,25 whereas commenters in the Southwest tend to focus on the difficulties posed by the deployment of solar resources.26 Further still, commenters in the South explain that in many areas the geography and regional conditions are less suitable to the development of significant wind and solar resources.27 Commenters therefore express a need for flexibility in responding to these challenges and urge the Commission to take this need into account in crafting any proposed rules.28

    22 SeeAppendix A.

    23AWEA at 2; Iberdrola at 8-10; NextEra 2-8.

    24Southern at 3; EEI at 2; ISO/RTO Council at 2.

    25 See, e.g.,NorthWestern at 4-6; Idaho Power at 2-4; Puget at 2.

    26 See, e.g.,NV Energy at 2, 6; Southern California Edison at 7.

    27 See, e.g.,Southern at 19.

    28Southern at 4-10; EEI at 2; ColumbiaGrid at 4-5.

    III. The Need for Reform

    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 thepro formaOATT to ensure that the services provided are not structured in an unduly discriminatory manner, that public utility transmission providers have access to needed information to facilitate the integration of VERs, and that transmission customers have a clear understanding of the determination of and obligations for the provision of ancillary services.29 The Commission believes that this set of proposed reforms represents a reasonable foundation upon which public utility transmission providers will be well positioned to manage system variability associated with increased numbers ofVERs. The Commission anticipates that the proposed operational and pricing reforms will result in a more efficient utilization of all generation, non-generation,30 and transmission resources and lay the basis for continued development, including the possibility of innovative solutions, such as efforts by the Joint Initiative in the West.

    29As part of this Proposed Rule, the Commission is also proposing a minor revision to 18 CFR 35.28. To date, when amending its regulations concerning thepro formaOATT, the Commission has listed by name Commission rulemaking proceedings promulgating and amending thepro formaOATT when explaining the details of a public utility transmission provider's obligation to have an OATT on file with the Commission (as indicated by, e.g., proposed regulatory text included in another recently issued Notice of Proposed Rulemaking:Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities,131 FERC ¶ 61,253 (2010)). This process is increasingly cumbersome. Thus as part of this Proposed Rule, the Commission proposes to no longer explicitly reference, by name, prior Commission rulemaking proceedings promulgating and amending thepro formaOATT in its regulations. Likewise, the Proposed Rule includes a similar change with respect to a public utility transmission provider's obligation to have standard generator interconnection procedures and agreements and standard small generator interconnection procedures and agreements on file with the Commission.

    30 SeeOrder No. 890, FERC Stats. & Regs. ¶ 31,241 at P 888 (modifying Schedules 2, 3, 4, 5, 6, and 9 of thepro formaOATT to indicate that the ancillary services provided in those rate schedules may be provided by generating units as well as other non-generation resources such as demand response where appropriate).

    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.31 In addition to this existing capacity, another 85 GW of wind generating capacity has been proposed to be on line by the end of 2012.32 The amount of new solar generating capacity also has increased in recent years, adding 351 MW in 2008 and 481 MW in 2009, bringing the total solar generating capacity to more than 2,000 MW.33

    31Ryan Wiser & Mark Bolinger, Lawrence Berkeley National Laboratory,2009 Wind Technologies Market Report3-5 (2010),available at http://www1.eere.energy.gov/windandhydro/pdfs/2009_wind_technologies_market_report.pdf.

    32Div. of Energy Market Oversight, Fed. Energy Regulatory Comm'n,2009 State of the Markets Report(2010), available athttp://www.ferc.gov/market-oversight/st-mkt-ovr/som-rpt-2009.pdf.

    33Solar Energy Industries Ass'n,US Solar Industry Year in Review2009, at 2,available at http://seia.org/galleries/default-file/2009%20Solar%20Industry%20Year%20in%20Review.pdf.

    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.34 Moreover, federal tax policies that provide incentives to the development of renewable generation facilities have been in place for a number of years. For example, the federal production tax credit, which has been in effect intermittently since the early 1990s, provides an inflation-adjusted credit for power produced from VERs and other renewable resources.35 In February 2009, the American Recovery and Reinvestment Act (ARRA) not only extended the production tax credit for a period of three additional years,36 but also instituted an investment tax credit, which allows developers of certain renewable generation facilities to take a 30 percent cash grant in lieu of the production tax credit.37 Other federal policies that provide incentives to renewable generation facilities include accelerated depreciation of certain renewable generation facilities and loan guarantee programs.

    34 SeeIntegrating VERs NOI, 130 FERC ¶ 61,053 at P 2 (citing Div. of Energy Market Oversight, Fed. Energy Regulatory Comm'n,Renewable Power and Energy Efficiency Market: Renewable Portfolio Standards 1 (2009), available at http://www.ferc.gov/market-oversight/othr-mkts/renew/othr-rnw-rps.pdf).

    3526 U.S.C. 45.

    36American Recovery and Reinvestment Tax Act of 2009, Pub. L. 111-5, sec. 1101, 123 Stat. 115, 319 (2009).

    37 Id.sec. 1102, 123 Stat. 115, 319-20.

    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.”38 The same observation is true for the operational reforms proposed here. Public policies that promote renewable resources accentuate the need for reforms to operational protocols that unduly discriminate against VERs and/or have the effect of maintaining rate structures that are no longer just and reasonable.

    38 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities,131 FERC ¶ 61,253, at P 36 (2010) (Transmission Planning and Cost Allocation Proposed Rule).

    16. As the number of VERs has increased, the Commission has received a variety of proposals that seek variations from thepro formaOATT and/or LGIA in order to address system needs resulting from the integration of VERs. In recent years, a number of public utility transmission providers have proposed to assess various forms of ancillary services charges to wind generating resources, while others have proposed revised interconnection standards addressing reporting requirements and additional ancillary service obligations.39 Consistent with many of the comments received in response to the Integrating VERs NOI, such filings suggest that thepro formaOATT and LGIA may need adjustments to address operational issues arising in response to the increased integration of VERs in individual balancing authority areas.

    39 See, e.g., NorthWestern Corp.,129 FERC ¶ 61,116 (2009) (NorthWestern),order on reh'g,131 FERC ¶ 61,202 (2010);Westar Energy Inc.,130 FERC ¶ 61,215 (2010) (Westar);Cal. Indep. Sys. Operator Corp.,131 FERC ¶ 61,087 (2010);Puget Sound Energy, Inc.,132 FERC ¶ 61,128 (2010) (Puget Sound).

    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 thede factoeffect of imposing an undue burden on VERs. The proposed reforms acknowledge that existing practices as well as the ancillary services used to manage system variability were developed at a time when virtually all generation on the system could be scheduled with relative precision and when only load exhibited significant degrees of within-hour variation. In proposing these reforms, the Commission seeks to ensure that VERs are integrated into the transmission system in a coherent and cost-effective manner, consistent with open access principles.

    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 Force40 and the work of the Joint Initiative.41 As such, the reforms proposed here do not purport to resolve all of the challenges associated with VER integration, nor are they intended to undermine progress being made in various regions regarding VER integration. The Commission's goal in this proceeding is simply to identify those basic reforms that can and should be implemented in the near term. The Commission believes that the reformsproposed herein can and should be implemented in a way that complements ongoing stakeholder proceedings.

    40 SeeNorth American Elec. Reliability Corp., Accommodating High Levels of Variable Generation(2009),available at http://www.nerc.com/files/IVGTF_Report_041609.pdf.

    41 SeeJoint Initiative at 3-11 (describing projects currently being developed by members of Columbia Grid, Northern Tier Transmission Group and WestConnect such as an Intra-Hour Transaction Accelerator Platform and a Dynamic Scheduling System).

    IV. Summary of Proposed Reforms

    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 theirpro formaLGIAs to incorporate provisions requiring interconnection customers whose generating facilities are VERs to provide certain meteorological and operational data to public utility transmission providers to facilitate public utility transmission providers' development and deployment of VER power production forecasting tools. Under the LGIA provisions proposed here, the interconnection customer whose generating facility is a VER would only be required to provide such data in the instance where the interconnecting public utility transmission provider is developing and/or deploying VER power production forecasting tools.

    21. Third, the Commission proposes to add a generic ancillary service rate schedule to thepro formaOATT through which a public utility transmission provider must offer generator regulation service, to the extent it is physically feasible to do so from its resources or from resources available to it, to transmission customers using transmission service to deliver energy from a generator located within the transmission provider's balancing authority area. Under this proposed rate schedule, a public utility transmission provider will have the opportunity to recover reserve service costs associated with management of supply-side variability. In Order No. 890, the Commission took a case-by-case approach to filings by public utility transmission providers seeking to recover the costs of additional regulation reserves associated with providing generator imbalance service.42 This existing policy, however, has led to uncertainty and allows the potential for undue discrimination. To prevent this uncertainty and potential undue discrimination, we believe it is appropriate now to propose a generic generator regulation reserve rate schedule that will delineate the rights and obligations of public utility transmission providers and customers with respect to the provision of this service.

    42Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 689 n.401,order on reh'g,Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 313. More recently, the Commission clarified transmission providers' obligation to offer generator regulation service by rejecting a transmission provider's proposal to require VERs exporting out of the transmission provider's balancing authority area to provide or arrange for their own generator regulation capacity.See NorthWestern,129 FERC ¶ 61,116 at P 24 (finding that the proposal to disclaim the obligation to provide the capacity reserves necessary to providing generator imbalance service would be inconsistent with the transmission provider's obligation to offer generator imbalance service set forth in thepro formaOATT).

    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.43 Therefore, in keeping with the suggestion of a number of commenters to allow individual regions to continue to develop solutions to the challenges unique to their characteristics and resources, and in recognition of commenters who seek Commission engagement on these issues, the Commission proposes to instruct its staff to monitor and conduct outreach with industry stakeholders to keep abreast of developments.

    43 See, e.g.,Joint Initiative at 7-12 (explaining ongoing efforts in the West to develop a dynamic scheduling system and intra-hour transaction accelerator platform to facilitate transactions among balancing authorities); ISO/RTO Council at 44 (indicating that ISOs and RTOs have begun to integrate centralized forecasting into reliability commitment processes); NERC,Integration of Variable Generation Task Force, 2009-2011 Work Plan (2009), available at http://www.nerc.com/docs/pc/ivgtf/IVGTF_Work_%20Plan_111309.pdf(detailing on-going efforts to establish mechanisms to calculate the capacity associated with VERs).See alsoOrder No. 890, FERC Stats. & Regs. ¶ 31,241 at P 1626-27 (requiring transmission providers to use an OASIS template that will be developed by the North American Energy Standards Board to post information concerning curtailments, including the circumstances and events leading to a firm service curtailment, specific customers and services curtailed, and the duration of the curtailment).

    V. Proposed Reforms A. Intra-Hourly Scheduling

    25. Outside of regions that have an RTO or ISO, resources typicallyschedule transmission service on an hourly basis, and adjustments to such schedules are permitted during the hour only for emergency situations that threaten reliability.44 In the Integrating VERs NOI, the Commission noted that existing scheduling practices were designed at a time when virtually all generation on the system could be scheduled with relative precision.45 The Commission also acknowledged that, with increasing numbers of VERs, system operators appear to be relying more on reserves, such as regulation reserves, to balance the variation in energy output from VERs.46

    44Section 13.8 of thepro formaOATT requires transmission customers to schedule use of firm point-to-point transmission service by 10:00 a.m. the day prior to operation. That section also gives the transmission provider the discretion to accept schedule changes no later than 20 minutes prior to the operating hour.

    45Integrating VERs NOI, 130 FERC ¶ 61,053 at P 18.

    46 Id.

    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.47 As a result, because of a resource's limited ability to adjust its schedules during the hour, the operational flexibility of all resources on the transmission provider's system may not be utilized.48

    47 Id.P 19.

    48 Id.

    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.49

    49 Id.P 18-21.

    1. Comments

    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.50 AWEA points out that the Avista Wind Integration Study similarly found wind integration costs would be reduced by 40-60 percent by moving from hourly to intra-hourly dispatch intervals.51 Additionally, AWEA asserts that Bonneville has publicly stated that wind integration costs on its system would be reduced by 80 percent by moving from hourly schedules to intra-hourly schedules.52 Bonneville states that intra-hour scheduling has the potential to help better manage the costs and operational impacts of VER generator imbalances.53

    50AWEA at 38 (citing M. Milligan & B. Kirby,Impact of Balancing Area Size, Obligation Sharing, and Ramping Capability on Wind Integration,27-29 (2007),available at http://www.nrel.gov/wind/systemsintegration/pdfs/2007/milligan_wind_integration_impacts.pdf).

    51AWEA at 20 (citing Avista Corp.,Wind Integration Study(2007),available at http://www.uwig.org/AvistaWindIntegrationStudy.pdf).

    52AWEA at 20 (citing Presentation by Bart McManus, Bonneville.Large Wind Integration Challenges and Solutions for Operations/System Reliabilityat slide 26 (Oct. 2008),available at http://www.uwig.org/Denver/McManus.pdf) (stating 10 minute schedule changes would solve approximately 80% of the issues Bonneville is anticipating).

    53Bonneville at 6.

    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.54 EEI states that for regions with significant amounts of VERs, it appears that shorter intervals would allow system operators to manage VER ramp events55 and variability, provide more accurate scheduling, reduce the reliance on regulating reserves and make it easier to meet NERC CPS-2.56 NERC claims that while additional system flexibility can come from many sources, such as the availability of flexible conventional resources and non-conventional resources such as storage and demand response programs, an additional contributor to greater system flexibility includes shorter scheduling intervals, for both within a balancing authority area and between balancing authority areas.57 Joint Initiative states that allowing transmission customers to schedule transactions within an operating hour increases operating flexibility for VERs and the rest of the system.58 NERC claims that the ideal scheduling increments to achieve optimum flexibility while still meeting relevant reliability requirements may be between five and fifteen minutes; however, this depends on system characteristics, the type of VERs present on the system, and the level of VER penetration.59

    54WECC at P 6.

    55Ramp events are instances where the generating facility experiences a significant change in electrical output.

    56EEI at 9.

    57NERC at 16.

    58Joint Initiative at 3.

    59NERC at 17-18.

    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.60 AWEA notes that shorter scheduling intervals will yield significant benefits even on transmission systems without wind energy, as there is significant intra-hour variability in load, as well as in the output of non-VER resources when they experience forced outages or otherwise fail to provide their scheduled output.61 AWEA also contends that moving to shorter dispatch intervals will actually improve power system reliability by freeing up additional system flexibility that is currently underutilized.62 Iberdrola argues that the Commission should modify itspro formaOATT to require, at a minimum, intra-hourly scheduling of generation, explaining that intra-hour scheduling will improve VER scheduling accuracy and reduce VER integration costs.63 Southern California Edison argues that the Commission should ensure that new scheduling tools, such as half-hour scheduling intervals, are available, as these could help reduce forecast errors, and in turn, result in optimal transmission utilization, market efficiency, and system reliability.64 Southern California Edison also explains that, because it does not expect reliability issues to arise from scheduling rule changes, NERC Reliability Standards will require minimal or no changes.65

    60AWEA at 16.

    61 Id.at 38.

    62 Id.at 40.

    63Iberdrola at 10.

    64Southern California Edison at 10-11.

    65Southern California Edison at 12.

    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 beallowed to explore and coordinate its own scheduling practices to suit its unique system needs through stakeholder processes. For example, EEI states that in light of the variation in market structures and rules throughout the country, it is unlikely that any single scheduling practice will suit all regions.66 EEI argues that the Commission should allow each region to explore its own flexible scheduling options and provide policy guidance that encourages flexible scheduling practices to the maximum extent possible.67 Bonneville argues that mandating intra-hour scheduling or standardizing national practices is premature.68 The ISO/RTO Council supports moving toward intra-hour scheduling across the inter-ties for purposes of VER integration where warranted by system needs.69

    66EEI at 8.

    67 Id.at 9.

    68Bonneville at 44.

    69ISO/RTO Council at 36.

    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.70 The Joint Initiative also explains that a number of utilities in the Northwest have begun to implement these practices to one degree or another.71 SMUD points out that the Western Systems Power Pool currently seeks to develop two new service schedules that will accommodate VERs through the provision of reserve services and intra-hour supplemental energy. For this reason, SMUD argues that the Commission should avoid taking actions where industry efforts are in progress to cost-effectively achieve similar goals, particularly when those efforts are further taking into account regional characteristics.72

    70Joint Initiative at 4.

    71 Id.at 5-6 (citing sub-hourly scheduling initiatives by the following: NV Energy, PacifiCorp, Bonneville, Puget, Portland General Electric, Avista Corp., Seattle City Light, Chelan County PUD, Grant County PUD, and Tacoma Power).

    72SMUD at 20.

    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.73 AWEA explains that the costs associated with the transition to an intra-hourly dispatch include: (1) Modifications of dispatch/energy management and NERC e-Tag systems in order to accommodate intra-hour schedules/settlements, (2) OATT revisions necessary to accommodate transmission reservations for periods of less than a full clock hour, and (3) possible staffing increases to handle the greater number of transactions.74

    73AWEA at 39.

    74 Id.

    34. Entergy states that it moved from hourly scheduling to twenty-minute anytime-scheduling several years ago.75 According to Entergy, no changes to the OATT, e-Tag or NERC rules were required.76 Entergy states that its scheduling systems were significantly modified to implement this additional flexibility, but such changes have proven to be manageable to date. Entergy cautions that if intra-hour scheduling is mandated, the burden on the system operators may increase, such as when there are reliability issues on the system.77 Entergy explains that at these times, system operators would have to handle intra-hour schedules and reliability issues simultaneously.78 Therefore, Entergy asks the Commission to proceed carefully and consider differences among balancing authority areas, in terms of software, manpower, and scheduling work load, before mandating intra-hour scheduling.79 Similarly, Northwestern argues that system automation will be necessary to allow much greater number of schedules and transmission service requests to be processed without impacting reliability.80 National Rural Electric Cooperative Association (NRECA) claims that a number of NERC standards would need to be reviewed to determine the impacts of a move towards flexible scheduling.81

    75Entergy at 2.

    76 Id.

    77 Id.

    78 Id.

    79 Id.

    80NorthWestern at 14.

    81NRECA at 30 (citing BAL (Resource and Demand Balancing), INT (Interchange Scheduling and Coordination), IRO (Interconnection Reliability Operations and Coordination), and MOD (Modeling, Data, and Analysis) Standards).

    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.82 NRECA explains that while changes to infrastructure required for trading may be absorbed by large entities, smaller cooperatives would be affected disproportionately because of their inability to spread the costs over the large volume of trade.83 NRECA claims that in any cost-benefit analysis, it is less likely that smaller entities will benefit, even over time, especially where they lack a large customer base, which is the case for many rural electric cooperatives.84 Consequently, NRECA contends that intra-hour scheduling is simply infeasible for some of its members at this time.85

    82NRECA at 28.

    83 Id.at 29.

    84 Id.

    85 Id.

    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.86 Second, commenters argue that the responsibility for scheduling efficiency should fall on VERs. These commenters generally argue that VERs should be required to maintain the accuracy of their schedules and should not expect public utility transmission providers to change scheduling practices that have worked in the past. Altresco states that maintaining scheduling practices is essential to the reliability of the grid, and that VERs should take responsibility for the reliability impact of the variability of their resource.87 Southern states that all generators (including VERs) should be responsible for providing accurate schedules and that the risk and responsibility for forecasting availability should always be the generator's responsibility and should not be shifted to the public utility transmission provider or system operator.88

    86Southern at 11.

    87Altresco at 5-6.

    88Southern at 11.

    2. Commission Discussion

    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 thepro formaOATT. Specifically, we preliminarily find that existing hourly transmission scheduling protocols expose transmission customers to excessive or unduly discriminatory generator imbalance charges and are insufficient to provide system operators with the flexibility to manage their system effectively and efficiently. Therefore, the Commission proposes to amend sections 13.8 and 14.6 of thepro formaOATT to provide transmission customers the option to schedule transmission service on an intra-hour basis, at intervals of 15 minutes.89 The Commission notes that the proposed 15-minute interval is consistent with the ideal time increments (i.e.,5 to 15 minutes) recommended by NERC to achieve greater flexibility while still meeting relevant reliability requirements.90 Additionally, the Commission notes that many commenters claim that shorter scheduling intervals may enhance system reliability.91 As such, we do not believe, as NRECA suggests, that an independent review of NERC standards is necessary to making this proposed reform. However, the Commission seeks comment on the issue to ensure that there is no inconsistency among relevant NERC standards and the proposed intra-hour scheduling tariff reform.

    89The Commission's proposed reform allows for intra-hour scheduling adjustments; it does not propose changes to the hourly transmission service reservations provided in the OATT.

    90NERC at 17-18.

    91NERC at 20, AWEA at 40, EEI at 29, Southern California Edison at 11-12, CalWEA at 7, Pacific Gas and Electric at 6, NaturEner at 11, and Wärtsilä at 7.

    38. As explained above, hourly transmission scheduling protocols were developed at a time when virtually all generation on th