Integration of Variable Energy Resources

Federal RegisterJul 13, 2012

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-11-000; Order No. 764]

Integration of Variable Energy Resources

AGENCY:

Federal Energy Regulatory Commission.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission is amending the

pro forma

Open Access Transmission Tariff to remove unduly discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional services. Specifically, this Final Rule removes barriers to the integration of variable energy resources by requiring each public utility transmission provider to: offer intra-hourly transmission scheduling; and, incorporate provisions into the

pro forma

Large Generator Interconnection Agreement requiring interconnection customers whose generating facilities are variable energy resources to provide meteorological and forced outage data to the public utility transmission provider for the purpose of power production forecasting.

DATES:

Effective Date:

This rule will become effective September 11, 2012.

FOR FURTHER INFORMATION CONTACT:

Jessica L. Cockrell (Technical Information), Office of Energy Policy and Innovation, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8190.

Andrea Hilliard (Legal Information), Office of General Counsel—Energy Markets, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8288.

SUPPLEMENTARY INFORMATION:

139 FERC ¶ 61,246

Department of Energy

Federal Energy Regulatory Commission

Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, John R. Norris, Cheryl A. LaFleur, and Tony T. Clark.

Issued June 22, 2012.

Table of Contents

I. Introduction

Background

II. The Need for Reform

A. Commission Proposal

B. Comments

C. Commission Determination

III. Legal Authority To Implement Proposed Reforms

A. Commission Proposal

B. Comments

C. Commission Determination

IV. Proposed Reforms

A. Intra-Hour Scheduling

1. Intra-Hour Scheduling Requirement

2. Implementation of Intra-Hour Scheduling

114

3. Other Issues

148

B. Data Reporting To Support Power Production Forecasting

154

1. Data Requirements

155

2. Definition of VER

200

3. Data Sharing

217

4. Cost Recovery

222

C. Generator Regulation Service-Capacity

233

1. Schedule 10-Generator Regulation and Frequency Response Service

234

2. Mechanics of a Generator Regulation Charge

276

3. Use of Contingency Reserves

336

V. Other Issues

343

1. Regulatory Text

343

2. Market Mechanisms

346

3. Power Factor Design

363

VI. Compliance

365

VII. Information Collection Statement

378

VIII. Environmental Analysis

383

IX. Regulatory Flexibility Act Analysis

384

X. Document Availability

385

XI. Effective Date and Congressional Notification

388

I. Introduction

1. In this Final Rule, the Commission acts under section 206 of the Federal Power Act (FPA) to adopt reforms that will remove barriers to the integration of variable energy resources (VER)

and ensure that the rates, terms, and conditions for Commission-jurisdictional services provided by public utility transmission providers are just and reasonable and not unduly discriminatory or preferential.

As the Commission noted in the Proposed Rule (75 FR 75336, December 2, 2010), VERs are making up an increasing percentage of new generating capacity being brought on-line.

This evolution in the Nation's generation fleet has caused the industry to reevaluate practices

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. As part of this evaluation, the Commission initiated this rulemaking proceeding to consider its own rules and, based on the comments received, concludes that reforms are needed in order to ensure that transmission customers are not exposed to excessive or unduly discriminatory charges and that public utility transmission providers have the information needed to efficiently manage reserve-related costs.

As defined in the Notice of Proposed Rulemaking, a Variable Energy Resource 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. This includes, for example, wind, solar thermal and photovoltaic, and hydrokinetic generating facilities.

See Integration of Variable Energy Resources Notice of Proposed Rulemaking,

FERC Stats. & Regs. ¶ 32,664, at P 64 (2010) (Proposed Rule).

16 U.S.C. 824e (2006).

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 13.

2. Specifically, the Commission amends the

pro forma

Open Access Transmission Tariff (OATT) to provide all transmission customers the option of using more frequent transmission scheduling intervals within each operating hour, at 15-minute intervals. There is currently no requirement to provide transmission customers the opportunity to adjust their transmission schedules within the hour to reflect changes in generation output. As a result, transmission customers have no ability under the

pro forma

OATT to mitigate Schedule 9 generator imbalance charges in situations when the transmission customer knows or believes that generation output will change within the hour. This lack of ability to update transmission schedules within the hour can cause charges for Schedule 9 generator imbalance service to be unjust and unreasonable or unduly discriminatory. Accordingly, the Commission amends the

pro forma

OATT to correct this deficiency.

3. The Commission also amends the

pro forma

Large Generator Interconnection Agreement (LGIA) to require new interconnection customers whose generating facilities are VERs to provide meteorological and forced outage data to the public utility transmission provider with which the customer is interconnected, where necessary for that public utility transmission provider to develop and deploy power production forecasting. 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 costly. This Final Rule facilitates a public utility transmission provider's use of power production forecasting by amending the

pro forma

LGIA to require new interconnection customers whose generating facilities are VERs to provide the underlying data necessary for public utility transmission providers to perform such forecasts accurately.

4. The Commission declines, however, to modify the

pro forma

OATT to include a new Schedule 10 governing generator regulation service as set forth in the Proposed Rule. The Commission intended for the proposed Schedule 10 to provide clarity to public utility transmission providers and transmission customers alike by setting forth a generic approach to the provision of generator regulation service. In response, numerous commenters urged the Commission not to adopt a standardized approach to generator regulation service, stressing that flexibility is needed in the design of capacity services needed to efficiently integrate VERs into the transmission system. The Commission agrees and, accordingly, will continue a case-by-case approach to evaluating proposed generator regulation service charges. To assist public utility transmission providers and their customers in the development and evaluation of such proposals, the Commission instead provides guidance in response to the comments submitted.

5. Taken together, the reforms adopted and guidance provided in this Final Rule are intended 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. This, in turn, fulfills our statutory obligation to ensure that Commission-jurisdictional services are provided at rates, terms, and conditions of service that are just and reasonable and not unduly discriminatory or preferential.

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 what they provide to themselves.

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, the

pro forma

OATT contains terms for scheduling transmission service and the provision of ancillary services.

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 Group

FERC,

225 F.3d 667 (D.C. Cir. 2000),

aff'd sub nom. New York

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 concluded that there was a pressing need for a single set of procedures and a single, uniformly applicable interconnection agreement for large generator interconnections.

Accordingly, the Commission adopted standard procedures (the Large Generator Interconnection Procedures or LGIP) and a standard agreement (the LGIA) for the interconnection of generation resources greater than 20 MW.

These reforms were designed to minimize opportunities for undue discrimination and to expedite the development of new generation, while protecting reliability and ensuring that rates are just and reasonable.

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'rs

FERC,

475 F.3d 1277 (D.C. Cir. 2007),

cert. denied,

552 U.S. 1230 (2008).

See

Order No. 2003, FERC Stats. & Regs. ¶ 31,146.

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.

Therefore, Commission 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.

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.

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

Id.

Interconnection for Wind Energy,

Order No. 661, FERC Stats. & Regs. ¶ 31,186,

order on reh'g,

Order No. 661-A, FERC Stats. & Regs. ¶ 31,198 (2005).

9. In recognition of the evolving energy industry and in a further effort to remedy the potential for undue discrimination, the Commission returned to the

pro forma

OATT in Order No. 890 and implemented a series of changes to the requirements of open access transmission service.

Among other things, the Commission adopted a set of transmission planning principles,

created a new

pro forma

ancillary service schedule designed to address generator imbalances,

and instituted a new conditional firm transmission product.

With regard to imbalance charges, the Commission found that such charges should be designed to provide appropriate incentives to keep schedules accurate without being excessive and otherwise result in consistency in charges between and among energy and generator imbalances.

The Commission recognized that intermittent resources, such as VERs, cannot always accurately follow their schedules and that high penalties for imbalances will not lessen the incentive to deviate from their schedules. Accordingly, the Commission exempted intermittent resources from third-tier deviation band of imbalance penalties.

Preventing Undue Discrimination and Preference in Transmission Service,

Order No. 890, FERC Stats. & Regs. ¶ 31,241,

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 (2009),

order on clarification,

Order No. 890-D, 129 FERC ¶ 61,126 (2009).

Order No. 890, FERC Stats. & Regs. ¶ 31,241 at PP 444-561. In June 2011, the Commission further amended the

pro forma

OATT to require, among other things, that each public utility transmission provider participate in a regional transmission planning process that produces a regional transmission plan and has a regional cost allocation method for the cost of new transmission facilities selected in a regional transmission plan for purposes of cost allocation.

Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities,

Order No. 1000, 176 FR 49842 (Aug. 11 2011), FERC Stats. & Regs. ¶ 31,323 (2011).

Order No. 890, FERC Stats. & Regs. ¶ 31,241 at PP 663-72.

Id.

PP 911-15.

Id.

P 72.

Id.

P 665.

10. Against this backdrop, the Commission in January 2010 issued a Notice of Inquiry in this proceeding to explore the extent to which barriers may exist that impede the reliable and efficient integration of VERs into the electric grid and whether reforms are needed to eliminate those barriers.

The Commission noted that the amount of VERs is rapidly increasing, reaching a point where such resources are becoming a significant component of the nation's energy supply portfolio.

In order to determine whether any rules, regulations, tariffs or industry practices within the Commission's jurisdiction hinder the reliable and efficient integration of VERs, the Commission sought comment on a range of 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.

The response from commenters was significant, with more than 135 entities submitting comments, many of which urged the Commission to undertake basic reforms in response to the increasing number of VERs being integrated into the system.

Integration of Variable Energy Resources Notice of Inquiry,

FERC Stats. & Regs. ¶ 35,563 (2010) (Notice of Inquiry).

Id.

P 2.

Id.

P 12.

II. The Need for Reform

A. Commission Proposal

11. In light of the changes occurring within the electric industry, and based on comments submitted in response to the January 2010 Notice of Inquiry, the Commission issued the Proposed Rule to remedy operational and other challenges associated with VER integration that may be causing undue discrimination and increased costs ultimately borne by consumers. The Commission preliminarily found that the proposed set of reforms would eliminate operational procedures that have the

de facto

effect of imposing an undue burden on VERs. The Commission stated that 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 its reforms, the Commission sought to ensure that VERs are integrated into the transmission system in a coherent and cost-effective manner, consistent with open access principles.

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 17.

B. Comments

12. Commenters largely support initiation of a rulemaking proceeding to consider potential reforms to reduce discrimination and improve the efficiency of the transmission system.

Invenergy Wind, for example, states that the Proposed Rule reflects an important step forward in providing the regulatory foundation that will create an incentive for improvements in system operations and procurement practices necessary to support the addition of renewable resources to the nation's historical generation mix. BP Companies comment that it is important for the Commission to provide a level playing field for wind and solar-generated power.

E.g.,

ACSF; AEP; AWEA; Argonne National Lab; BP Companies; Business Council; California ISO; CMUA; CEERT; Center for Rural Affairs; Clean Line; CGC; Defenders of Wildlife; Dominion; EEI; Environmental Defense Fund; Exelon; First Wind; Iberdrola; Idaho Power; ITC Companies; ISO New England; Independent Power Producers Coalition—West; ISO/RTO Council; Invenergy Wind; Large Public Power Council; Massachusetts DPU; MidAmerican; Midwest ISO Transmission Owners; M-S-R Public Power Agency; National Grid; NaturEner; Oregon & New Mexico PUC; NextEra; NorthWestern; PNW Parties; PJM; Powerex; Public Interest Organizations; RenewElec; SMUD; San Diego Gas & Electric; SEIA; Southern California Edison; SWEA; Southwestern; Sunflower and Mid-Kansas; Tacoma Power; Vestas; Western Farmers; Western Grid; Xcel.

13. Many commenters point to the importance of the Proposed Rule in removing market barriers to VER integration. NextEra comments that the instant proceeding is important because VERs have been developed in relatively modest amounts until recent years, and the existing market rules were designed to reflect the characteristics of more traditional generating resources (e.g., coal, natural gas and nuclear generation) rather than VERs. NextEra contends that existing rules were aimed at addressing the preferences and requirements of the resources and systems in the past, rather than to anticipate future changes. CEERT states that the Commission's initiative to remove market and operational barriers to VERs integration and eliminate undue discrimination against VERs is critical to making wholesale power markets more competitive and ensuring a sustainable energy future.

14. Iberdrola contends that this proceeding is the best opportunity available for the federal government to encourage the responsible development of renewable energy resources, and to avoid inadvertently stifling the growth

of renewable energy resources in an effort to protect the economic interests of incumbents. Similarly, NaturEner comments that the reforms are long overdue and should be implemented without further delay and in a manner requiring prompt compliance. This proceeding, NaturEner states, represents substantial progress towards the elimination of antiquated rules, requirements and processes, a significant reduction in duplication, unnecessary expenditures and inefficient allocation of resources, as well as an important step towards making the grid more robust, economical, and equitable.

15. Oregon & New Mexico PUC state that the Commission can play a valuable role in enabling the western electricity industry to reach state renewable energy goals at a reasonable cost to consumers by exercising its jurisdiction in these areas. Oregon & New Mexico PUC submit that the proposals in the Proposed Rule are an important step toward building the necessary foundation to integrate significant amounts of wind and solar in the West. Defenders of Wildlife similarly contend that by establishing a new rule which encourages VER integration, and long-term and much needed infrastructure investments can be made today to help spur the nation's growing renewable energy economy. ACSF states its strong support for Commission action to integrate VERs into a smarter, cleaner, and more flexible energy grid, whose principal design features should enable much more widespread investment and deployment of integrated and hybrid VER generation systems. ACSF states it is critical that the Commission exercise its authority to develop policies that send adequate economic signals that permit the country's most flexible, clean generation sources to provide complementary power for VERs.

C. Commission Determination

16. As noted above, the Commission initiated this proceeding through the issuance of a Notice of Inquiry to obtain information on barriers to the integration of VERs. The Commission sought to 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. The Commission explained that the changing characteristics of the nation's generation portfolio compelled a fresh look at existing policies and practices, leading the Commission to seek comment on a range of issues.

17. Based on its review of comments to the Notice of Inquiry, the Commission focused in the Proposed Rule on a series of basic reforms regarding transmission scheduling, data reporting requirements, and charges for generator regulation service that can and should be implemented in the near term.

The Commission explained that, taken together, the Proposed Reforms were 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.

The Commission acknowledged that the proposed reforms focused on discrete operational protocols that were only a subset of the issues for which comment was sought in the Notice of Inquiry.

The Commission stated its belief that focusing on the particular set of reforms proposed would provide a reasonable foundation for public utility transmission providers seeking to manage system variability associated with increased numbers of VERs and that further study is required for many of the remaining issues raised in the Notice of Inquiry.

Proposed Rule, FERC Stats. & Regs ¶ 32,664 at P 18.

Id.

P 19.

Id.

PP 23-24.

Id.

PP 12, 24.

18. The Commission received more than 1900 pages of initial and reply comments in response to the Proposed Rule. While differing in opinion on the merits of particular aspects of the Commission's proposal, commenters generally support the Commission's efforts to evaluate its rules through this rulemaking to explore further opportunities to reduce undue discrimination and reduce costs ultimately borne by consumers through more efficient use of the transmission system. Based on these comments, the Commission concludes that it is appropriate to act at this time to revise the transmission scheduling requirements of the

pro forma

OATT and incorporate data reporting requirements into the

pro forma

LGIA, as discussed in further detail later in this Final Rule.

As discussed throughout this Final Rule, these reforms are necessary to ensure that transmission customers are not exposed to excessive or unduly discriminatory charges for Schedule 9 generator imbalance service and to provide public utility transmission providers with information necessary to more efficiently manage reserve-related costs recovered from transmission customers through other ancillary services charges.

For the reasons discussed in Schedule 10 below, the Commission declines to standardize charges for generator regulation service through the adoption of a generic Schedule 10 to the

pro forma

OATT as suggested in the Proposed Rule.

19. The Commission takes this action now recognizing that the composition of the electric generation portfolio continues to change. VERs are making up an increasing percentage of new generating capacity being brought on-line. New wind generating capacity accounted for 35 percent of all newly installed generating capacity from 2007-2010.

As of December 2011, nearly 12,000 MW of additional wind generating capacity has been brought online and another 8,320 MW of wind generating capacity is currently under construction.

Current projections indicate that this expansion will continue, with the Energy Information Agency forecasting that generation from wind power will nearly double between 2009 and 2035.

This recent and future growth is being facilitated by developments in state and federal public policies that encourage the expansion of VER generation.

See

American Wind Energy Association,

Wind Power Outlook 2011

(Apr. 2011),

available at http://www.awea.org/_cs_upload/learnabout/publications/reports/8546_1.pdf.

American Wind Energy Association,

U.S. Wind Industry Fourth Quarter 2011 Market Report

(Jan. 2012),

available at http://www.awea.org/learnabout/industry_stats/upload/4Q-2011-AWEA-Public-Market-Report_1-31.pdf.

In addition, the amount of new photovoltaic generating capacity in 2011 increased by 108 percent over 2010 amounts, adding 1,855 MW of PV and bringing the total solar generating capacity to more than 4,470 MW. Utility installations increased by 185 percent in 2011, far more than residential or commercial market segments.

See

Solar Energy Industries Ass'n,

US Solar Market Insight Report 2011 Year-in-Review Executive Summary

(Mar. 2012),

available at http://www.seia.org/galleries/pdf/SMI-YIR-2011-ES.pdf.

Annual Energy Outlook at 75,

available at http://www.eia.gov/forecasts/archive/aeo11/pdf/0383(2011).pdf.

For example, as of May 2011, 30 states and the District of Columbia have a renewable portfolio standard or goal. FERC, Div. of Energy Market Oversight,

Renewable Power and Energy Efficiency Market: Renewable Portfolio Standards

1 (updated May 2011),

available at http://www.ferc.gov/market-oversight/othr-mkts/renew/othr-rnw-rps.pdf).

In addition, 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. 26 U.S.C. 45 (2007). In February 2009, the American Recovery and Reinvestment Act not only extended the production tax credit for a period of three additional years 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. American Recovery and Reinvestment Tax Act of 2009, Pub. L. 111-5, § 1101, 123 Stat. 115, 319-20 (2009). Other federal policies that provide incentives to renewable generation facilities include accelerated

depreciation of certain renewable generation facilities and loan guarantee programs.

20. As NERC has noted, higher levels of variable generation can alter the operation and characteristics of the bulk power system.

Increasing the relative amount of variable generation on a system can increase operational uncertainty that the system operator must manage through operating criteria, practices and procedures, including the commitment of adequate reserves.

However, many of these operational protocols were developed for generation resources with a different set of characteristics. For example, the hourly scheduling protocols of the

pro forma

OATT reflect historical practices associated with operation of conventional generating resources that are relatively predictable and controllable when compared to VERs. Similarly, the interconnection requirements of Order No. 2003 were based on the needs of traditional synchronous generators, leading the Commission to revisit those requirements as applied to large wind generators in Order Nos. 661 and 661-A.

NERC,

Accommodating High Levels of Variable Generation

at 8,

available at http://www.nerc.com/docs/pc/ivgtf/IVGTF_Report_041609.pdf.

Id.

at 59.

21. In Order No. 1000, the Commission recognized that changes in the generation mix influence the need for new transmission facilities and, as a result, Commission policies governing transmission planning and cost allocation.

The Commission concluded there that the increased focus on investment in new transmission projects made it critical to implement planning and cost allocation reforms to ensure that the transmission projects that come to fruition efficiently and cost-effectively meet regional needs. The Commission reaches a similar conclusion here. Changes in the generation mix and underlying public policies influencing investment in VER generation have accentuated the need to reform existing practices that unduly discriminate against VERs or otherwise impair the ability of public utility transmission providers and their customers to manage costs associated with VER integration effectively.

Order No. 1000, 76 FR 49842, FERC Stats. & Regs. ¶ 31,323 at PP 45-46.

22. Specifically, we find that the adoption of intra-hour scheduling and data reporting to support power production forecasting will remedy undue discrimination and ensure just and reasonable rates through more efficient utilization of transmission and generation resources.

With regard to transmission scheduling practices, existing hourly scheduling protocols can expose transmission customers to excessive or unduly discriminatory generator imbalance charges. Generator imbalance charges are 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, and also to provide an appropriate incentive for transmission customers to maintain accurate schedules. Under Schedule 9 of the

pro forma

OATT, there is no requirement to provide customers the opportunity to adjust their transmission schedules within the hour to reflect changes in generator output. As a result, transmission customers have no ability under the

pro forma

OATT to mitigate Schedule 9 generator imbalance charges in situations where the customer knows or believes that generation output will change within the hour. Implementation of intra-hour scheduling under this Final Rule will provide VERs and other transmission customers the flexibility to adjust their transmission schedules, thus limiting their exposure to imbalance charges. Over time, implementation of intra-hour scheduling also will allow public utility transmission providers to rely more on planned scheduling and dispatch procedures, and less on reserves, to maintain overall system balance.

In the Proposed Rule, the Commission also proposed to modify the

pro forma

OATT to include a new Schedule 10 governing generator regulation service. For the reasons discussed elsewhere in this Final Rule, the Commission declines to adopt that aspect of the Proposed Rule, instead providing guidance in response to comments submitted to assist public utility transmission providers and their customers in the development and evaluation of proposals on a case-by-case basis.

23. With regard to data reporting to support power production forecasting, the lack of data reporting requirements can limit the ability of public utility transmission providers to develop and deploy power production forecasts in an effort to more efficiently manage operating costs associated with the integration of VERs interconnecting to their systems. Under the existing requirements of the

pro forma

LGIA, public utility transmission providers are permitted to request this information, but there is no obligation for interconnection customers whose generating facilities are VERs to provide it. Implementation of reporting requirements commensurate with the power production forecasting employed by the public utility transmission provider will allow for more accurate commitment or de-commitment of resources providing reserves, ensuring that reserve-related charges imposed on customers remain just and reasonable and not unduly discriminatory or preferential. While the Commission declines to adopt a

pro forma

generator regulation and frequency response service, we note that public utility transmission providers that decide to file with the Commission to impose such a charge should, as part of any filing, consider the affect of the reforms we adopt in this Final Rule when developing proposed reserve capacity costs and evaluating whether to require different transmission customers to purchase or otherwise account for different quantities of generator regulation reserves.

24. Although focused on discrete issues, the implementation of intra-hour scheduling and reporting requirements through this Final Rule will allow for the efficient utilization of transmission and generation resources as an increasing amount of VER generation is integrated into the system. This in turn will ensure that the rates, terms, and conditions for Commission-jurisdictional services provided by public utility transmission providers are just and reasonable and not unduly discriminatory. Our actions here are intended to build on, rather than undermine, existing efforts at the regional level to address VER integration. The Commission acknowledges that significant work has been done through industry initiatives seeking to craft regional solutions to the challenges associated with VER integration. For example, many public utility transmission providers in the Western Interconnection have implemented some form of transmission scheduling at 30-minute intervals.

The Commission is acting here to implement a minimum set of requirements for all public utility transmission providers and new interconnection customers whose generating facilities are VERs as necessary to facilitate the efficient integration of VERs. The Commission appreciates that these requirements go beyond some existing activities. The Commission nonetheless concludes that the reforms adopted herein are

necessary to ensure that Commission-jurisdictional services are being provided at rates, terms and conditions that are just and reasonable and not unduly discriminatory or preferential.

See, e.g., Ariz. Pub. Service Co.,

137 FERC ¶ 61,023 (2011);

NorthWestern Corp.,

136 FERC ¶ 61,119 (2011). We note that the Joint Initiative indicated in its comments at page 6 that its first step in offering 30-minute scheduling “is intended to address unanticipated events, not to move to half-hour scheduling.” In addition, based on business practices posted on OASIS, some transmission providers reserve the right to suspend 30-minute scheduling.

III. Legal Authority To Implement Proposed Reforms

A. Commission Proposal

25. In the Proposed Rule, the Commission preliminarily found 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. Thus, the Commission proposed the following three reforms that require public utility transmission providers to: (1) Amend the

pro forma

OATT to require intra-hourly transmission scheduling; (2) amend the

pro forma

LGIA 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 the

pro forma

OATT 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 preliminarily concluded that the proposed rules are necessary to ensure that rates for Commission-jurisdictional services are just and reasonable and to remedy undue discrimination in existing transmission system operations.

Throughout this Final Rule the term Balancing Authority is used as defined by the North American Electric Reliability Cooperation (NERC). NERC, Glossary of Terms, available at

http://www.nerc.com/files/Glossary_of_Terms_2012January11.pdf.

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 23.

B. Comments

26. Some commenters take issue with the Commission's authority to mandate the tariff amendments contained in the Proposed Rule. With regard to forecasting and 15-minute scheduling, EEI and Southern assert that the Proposed Rule does not articulate a sufficient basis for changing existing tariff-based scheduling requirements under section 206 of the FPA.

Specifically, EEI and Southern question whether the Commission is relying upon record findings to support these proposed requirements. EEI and Southern submit that sections 205 and 206 “are simply parts of a single statutory scheme under which all rates are

established initially by the

[public utilities], by contract or otherwise. * * * Thus, FERC plays an essentially passive and reactive role under section 205.”

EEI and Southern maintain that these types of decisions should be left to public utility transmission providers and RTOs and should be informed by regional conditions and not dictated on a generic basis.

EEI and Southern argue, for example, that the Commission must rely upon factual, record findings to support these proposed mandates. EEI (citing

National Fuels

FERC,

468 F.3d 831, 839-44 (D.C. Cir. 2006)); Southern (citing, e.g.,

National Fuels,

468 F.3d 831, 839-44).

EEI (citing

Atlantic City

FERC,

295 F.3d 1,21 (D.C. Cir. 2002) (quoting

United Gas Pipe Line Co.

Mobile Gas Ser

. Corp.,

350 U.S. 332341 (1956) and

City of Winnfield

FERC,

744 F.2d 871, 876 (D.C. Cir. 1984)); Southern (citing

Atlantic City

FERC,

295 F.3d 1,21 (D.C. Cir. 2002) (quoting

United Gas Pipe Line Co.

Mobile Gas Ser

Corp,

350 U.S. 332341 (1956) and

City of Winnfield

FERC,

744 F.2d 871, 876 (D.C. Cir. 1984)).

27. In contrast, NextEra states that assertions that there is no record evidence not only ignore how current rules disadvantage VERs, but misunderstand the Commission's authority to promulgate rules of general applicability. NextEra points out that the Commission does not have to find that the tariffs or practices of every utility under its jurisdiction are unjust and unreasonable in order to proceed with a rulemaking. Rather, NextEra asserts that courts have confirmed that the Commission is not required to make individual findings when it exercises its statutory authority to promulgate a rule of general applicability.

28. Certain commenters also question the Commission's reliance in this proceeding on its authority to remedy undue discrimination.

Specifically, EEI and Southern take issue with the Commission's conclusion that procedures (such as hourly scheduling) applied uniformly to all transmission customers are unduly discriminatory under the FPA when those procedures arguably have a disparate impact on different types of transmission customers and/or place those customers at a competitive disadvantage in wholesale markets. EEI and Southern submit that the Commission and the DC Circuit have rejected the notion that facially-neutral technology and customer-blind transmission scheduling procedures are unduly discriminatory under section 205 of the FPA because of the effects or impacts of those requirements on different customer groups.

EEI asks the Commission to clarify that facially-neutral, technology- and customer-blind operational practices will not be deemed unduly discriminatory solely by virtue of disparate impact on dissimilar technologies or customers, and that the Proposed Rule is not intended as a departure from precedent in determining undue discrimination.

E.g.,

Southern; EEI.

Southern (citing

Enron Power Marketing, Inc.

FERC,

296 F.3d 1148 (D.C. Cir. 2002) (

Enron

)); EEI (citing

Enron,

296 F.3d 1148).

29. Similarly, Public Power Council questions the sufficiency of the Commission's evidence of undue discrimination against VERs. Public Power Council asserts that the Commission has not demonstrated that the costs of capacity charged to VERs were not incurred for the benefit of VERs, or would not have been incurred but for the needs of VERs, and that the costs of capacity were not prudently incurred. Public Power Council submits that the rules applicable to generation for the payment of balancing capacity costs are facially neutral, as VERs require more balancing capacity than non-variable resources. According to Public Power Council, if a load's characteristics required extraordinary amounts of balancing capacity, it seems unlikely that it or anyone else would complain that the rules should be changed to reduce costs. Thus, Public Power Council argues that a federal policy to promote renewable generation cannot be translated into an overriding mandate to prefer VERs.

30. ELCON asserts, with regard to 15-minute scheduling, forecasting, and Schedule 10 service, that the principle flaw in the Proposed Rule is its reliance on the supposition that operating practices favoring the dispatchability of resources are a form of “preferential treatment,” and therefore that non-dispatchable resources such as VERs are being discriminated against. ELCON explains that the proposals set forth in the Proposed Rule are costly measures that would apply preferentially to just one class of generation—VERs—seeking to address discrimination that does not actually exist.

31. Southern asserts that, in instances where a single rate is found to have disparate cost impacts upon dissimilar customers, such a result is only considered unduly discriminatory if such differences cannot be cost-

justified.

Southern argues that existing scheduling and imbalance practices are not unduly discriminatory against VERs. Southern explains that VER customers pay more energy imbalance charges than others because they impose more imbalance burdens and costs upon the system.

Similarly, ELCON maintains that the cost causation model of cost allocation results in greater economic efficiency by retaining a direct tie between the costs and the benefits of a given project. ELCON argues that in the instant case, there is no tie to the costs customers will be forced to bear.

Southern (citing

Ala Elec. Coop.

FERC,

684 F.2d 20, 29 (D.C. Cir. 1982) (

Alabama Power

)).

Southern further contends that VERs are not similarly situated to dispatchable generation for sheduling and imbalance purposes.

Id.

(citing

City of Vernon

FERC,

845 F.2d 1042, 1045-46 (D.C. Cir. 1988)).

32. Midwest ISO Transmission Owners contend that all generation resources should be treated on a comparable basis, and none should be subject to undue discrimination or receive an undue preference. Midwest ISO Transmission Owners state that in the Midwest ISO this will mean that VERs are subject to the same requirements as existing resources unless additional requirements are necessary to maintain reliability.

ELCON argues that the Commission should apply a principle of “source neutrality,” which it contends will create a level playing field for all alternative resources including demand response and combined heat and power. ELCON explains that, without the adoption of a resource planning paradigm based on source neutrality, almost any non-traditional resource may fall prey to undue discrimination with respect to transmission of electric energy and sales of electric energy for resale in interstate markets.

Midwest ISO Transmission Owners (referencing Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at PP 37, 45, 55 (stating that proposed reforms in intra-hour scheduling and power production forecasting can enhance reliability).

33. On the contrary, NextEra argues that most market rules are not oriented to aiding VERs, and may in fact present obstacles to VERs. NextEra states that, even in RTO markets, the fundamental principles around which markets are designed are day-ahead schedules, economic dispatch, and the impact of congestion. NextEra points out that none of these concepts are particularly applicable to VERs, which can have difficulty producing accurate day-ahead forecasts, are not truly dispatchable, and have limited ability to choose sites to reduce congestion. For example, NextEra contends that while nodal representation of generators may work best for dispatchable units, a system that was designed around non-dispatchable VERs could include features such as aggregation and scheduling from a portfolio of generators that might be staggered geographically, so as to reduce variability and forecasting errors and allow pooling of energy imbalances and deviations.

34. NextEra explains that when the Commission remedies unfair rules and practices, it is not doing so to create a preference for the type of entity that was being harmed, but rather to benefit the market and consumers. Thus, NextEra maintains that Commission action to provide greater flexibility, promote innovation or foster participation by new market entrants will ultimately benefit energy markets and consumers, even though the measure itself focuses on changes or incentives for one type of market participant.

35. Finally, with regard to meteorological forecasting in particular, Southern contends that such forecasting practices are beyond the scope of the Commission's authority. Southern states that courts have recognized that the Commission “is a `creature of statute,' having no constitutional or common law existence or authority, but only those authorities conferred upon it by Congress.”

Southern contends that public utilities have long engaged in meteorological forecasting for load forecasting and dispatch purposes. Southern argues that there never has been an indication that such practices were within the scope of the Commission's jurisdiction, and the advent of VER generation has not added such forecasting to the scope of the Commission's authority.

Southern (citing

Cal. Indep. Sys. Operator Co.

FERC,

372 F.3d 395, 398 (D.C. Cir. 2004) (citing

Atlantic City Elec. Co.

FERC,

295 F.3d at 8)).

C. Commission Determination

36. The Commission concludes that it has authority under section 206 of the FPA to adopt the reforms set forth in this Final Rule. Section 313(b) of the FPA makes Commission findings of fact conclusive if they are supported by substantial evidence.

When applied in a rulemaking context, “the substantial evidence test is identical to the familiar arbitrary and capricious standard.”

The Commission thus must show that a “reasonable mind might accept” that the evidentiary record here is “adequate to support a conclusion,”

that this Final Rule is needed to address barriers to the integration of VERs by remedying challenges that may be causing undue discrimination and increased costs ultimately borne by consumers. As explained below, the Commission has met its burden.

16 U.S.C. 825l(b).

Wisc. Gas Co.

FERC,

770 F.2d 1144, 1156 (1985);

see also Associated Gas Distrib.

FERC,

824 F.2d 981, at 1018 (D.C. Cir. 1987).

Dickenson

Zurko,

527 U.S. 150, 155 (1999).

37. As discussed throughout this Final Rule, the reforms adopted in this proceeding are intended to ensure that rates for jurisdictional services remain both just and reasonable and are not unduly discriminatory or preferential. In this way, the reforms contained in this Final Rule build on the work of Order No. 890, in which the Commission made several reforms to the

pro forma

OATT, in part because of a recognition that the mix of generation resources on the system was changing and that not all generation resources were similarly situated.

Like the reforms instituted in Order No. 890, the reforms adopted herein are designed to remedy deficiencies in existing requirements that can cause the rates, terms, and conditions of jurisdictional services to become unjust and unreasonable or unduly discriminatory or preferential.

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 2 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 5. The Commission further 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. Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 663 (requiring that generator imbalance provisions account for the special circumstances presented by intermittent generators).

38. The basis for adopting changes to the

pro forma

OATT and

pro forma

LGIA is discussed in the sections below addressing reforms to transmission scheduling practices and the reporting of meteorological data. There the Commission concludes that changes to scheduling practices are necessary in order to ensure that charges for generator imbalance service under schedule 9 of the

pro forma

OATT and for generator regulation service, as relevant, are just and reasonable and not unduly discriminatory. The Commission also concludes that, without the reporting requirements adopted herein, the terms of the

pro forma

LGIA may impair the ability of public utility transmission providers to develop and deploy power production forecasting, which in turn can lead to rates for jurisdictional services that are unjust and unreasonable or unduly discriminatory.

39. The Commission concludes that we have the authority to make these determinations under applicable precedent, including

National Fuel.

In that case, the court found that the

Commission had not met the substantial evidence standard when it sought to extend its Standards of Conduct that regulate natural gas pipelines' interactions with their marketing affiliates to their interactions with their non-marketing affiliates. The court noted that it had previously upheld the Standards of Conduct as applied to marketing affiliates because the Commission had demonstrated both a theoretical threat, namely that pipelines could grant undue preferences to their marketing affiliates, and substantial record evidence that such abuse had actually occurred.

In considering the Commission's order extending the Standards to non-marketing affiliates, the court found that the Commission had cited a theoretical threat of undue preference, but had not cited a single example of actual abuse by non-marketing affiliates. It concluded that instead of providing evidence of a real problem with respect to non-marketing affiliates, the Commission had relied either on examples of abuse by marketing affiliates, and therefore already covered by the old Standards, or on comments from the rulemaking that merely reiterated a theoretical potential for abuse.

The court remanded the matter and noted that if the Commission chose to proceed with promulgating the new Standards, it would have to develop a factual record to support them. If the Commission decided instead to rely solely on a theoretical threat, it would need to show how this threat justified the costs that the Standards would create.

National Fuel,

468 F.3d at 840.

Id.

at 841.

Id.

at 844.

40. Our actions in this Final Rule are consistent with the standards that the court set forth in

National Fuel.

We conclude that, 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. In other words, the problem that the Commission seeks to resolve represents a “theoretical threat,” in the words of the

National Fuel

decision, the features of which are discussed throughout the body of this Final Rule in the context of each of the reforms adopted herein. This threat is significant enough to justify the reforms imposed by this Final Rule. It is not one that can be addressed adequately or efficiently through the adjudication of individual complaints.

In the terminology of

National Fuel,

the remedy we adopt is justified sufficiently by the “theoretical threat” identified herein, even without “record evidence of abuse.” The actual experiences of problems cited in the record herein provide additional support for our action, but are not necessary to justify the remedy.

Individual adjudications by their nature focus on discrete questions of a specific case. Rules setting forth general principles are necessary to ensure that adequate processes are in place.

41. Citing

Enron,

Southern and EEI also argue that the Commission does not have the authority to remedy undue discrimination in situations where facially neutral operational practices result in a disparate impact on different market participants. The Commission disagrees.

Enron

involved an OATT Filing by a public utility (Entergy) in which the utility sought to require point-to-point transmission customers to designate specific sources and sinks for transmission service. The proposal also set forth what the utility would accept as a valid source or sink, prohibiting a generator (or generation-only control area) from being a sink, and prohibiting a load (or load-only control area) from being a source.

Customers objected to the proposal, arguing that the provision would not limit Entergy's ability to reserve capacity and schedule in and out of its control area because it had load and generation within its control area, but would prohibit similar transactions from customers operating control areas completely surrounded by Entergy that sought to set up transactions in and out of those control areas. The Commission evaluated Entergy's proposal under the applicable standard of review,

i.e., whether the OATT Filing was consistent with or superior to the Order No. 888

pro forma

OATT. The Commission accepted the proposal, and the United States Court of Appeals for the District of Columbia Circuit upheld the decision.

Enron,

296 F.3d at 1151.

Id.

at 1153-54.

42. We find that commenters' reliance on

Enron

is misplaced. In

Enron,

the Commission reviewed a tariff filing made under section 205 of the FPA to determine if it was consistent with or superior to the

pro forma

OATT. The scope of that analysis is not analogous to that of our inquiry in this proceeding, which is to determine if changes to the

pro forma

OATT and

pro forma

LGIA are necessary to ensure that rates for jurisdictional services remain just and reasonable and not unduly discriminatory. In any event, to the extent that

Enron

may be relevant to a rulemaking proceeding of general applicability, Southern and EEI appear to misunderstand the result in

Enron.

In that case, the court found that it was neither arbitrary nor capricious for the Commission to accept a tariff provision forbidding the designation of a generator-only control area as a sink and a load-only control area as a source as comparable to the

pro forma

OATT.

In addition to this holding, the court indicated that it was sufficient for the Commission to address comparability of an OATT (the applicable standard in that proceeding) “on the basis of the terms and conditions offered to customers, not on the usefulness of those terms and conditions to a particular customer because of that customer's capacities and needs,” noting also that the Commission found that the provision was not discriminatory.

Id.

at 1151-52.

Id.

at 1151. The court further found that the Commission adequately addressed charges that the provision would lead to discriminatory treatment by accepting the utility's commitment to apply the provision on a nondiscriminatory basis.

43.

Enron

did not, as Southern and EEI suggest, reject the notion that facially-neutral, technology- and customer-blind operational practices could be found to be unduly discriminatory because of the effects or impacts of those requirements on different customer groups. Instead, the relevant

Enron dicta

indicate that the Commission

could

sustain a determination that a tariff provision is comparable to the

pro forma

OATT where it offers the same terms and conditions to customers, notwithstanding a difference in how different customers will use or benefit from those tariff provisions.

However, nothing in

Enron

mandates that result.

Id.

44. Our conclusion that Southern and EEI erred in their interpretation of

Enron

is bolstered by other cases included in the comments of both parties. For example, Southern and EEI cite

Alabama Power

for the proposition that, in instances where a single rate is found to have disparate cost impacts on dissimilar customers, such a result is only considered unduly discriminatory if the differences cannot be cost justified.

Alabama Power,

the issue for the court was whether an application of the same rate to two groups of customers that were similar in many respects may nevertheless violate statutory prohibitions against unduly discriminatory rate schemes. That case involved rate filings by a utility that

applied the same rate to two groups of wholesale service customers. One group alleged that this single rate represented a misallocation of costs, resulting in that group paying significantly more (and the other paying significantly less) than the costs for which its members were responsible. The court held that notwithstanding the fact that the same rate applied to both groups of customers, the Commission was obligated to evaluate whether the different costs imposed by those two groups rendered the use of a single rate unduly discriminatory.

Southern (citing

Alabama Power,

684 F.2d at 29); EEI (citing

Alabama Power,

684 F.2d 20).

Alabama Power,

684 F.2d at 28-29.

45. Southern argues that a finding in the Proposed Rule—that existing hourly transmission scheduling protocols expose transmission customers to “excessive or unduly discriminatory generator imbalance charges”—may run afoul of

Alabama Power

because VER customers require greater amounts of imbalance service and therefore should be required to pay more in the way of imbalance charges.

Southern and EEI contend that, because VERs are not similarly situated to dispatchable generation for scheduling and imbalance purposes, existing scheduling and imbalance practices cannot be unduly discriminatory toward VERs.

Similarly, ELCON argues that the Proposed Rule would require all ratepayers to subsidize the integration of VERs despite not receiving any benefits, thereby violating cost causation principles.

Southern (citing Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 37).

Both Southern and EEI cite additional authority for this point, i.e., that in order to demonstrate that it was unduly discriminated against, a party must show that it is similarly situated to another party receiving different treatment.

See

EEI (citing

Ark. Elec. Energy Consumers

FERC,

290 F.3d 362 (D.C. Cir. 2002) (“a rate is not `unduly' preferential or `unreasonably' ” discriminatory in violation of the FPA if disparate effect of transmission or sale of electric energy by the jurisdictional utility can justify the disparate effect”)); Southern (citing

City of Vernon

FERC,

845 F.2d 1042, 1045-46 (D.C. Cir. 1988) (“The Commission's opinion sets forth a two-part test for discriminatory treatment where different rates or services are offered, requiring a showing that the unequally treated customers are `similarly situated,' and that the service sought is the `same service' actually offered elsewhere.”) & n.2 (“FERC has typically relied on factors like these in defining a prima facie case of undue discrimination.”);

see,

e.g.,

Sacramento Mun. Util. Dist.

FERC,

474 F.3d 797, 802 (D.C. Cir. 2007) (“In order for PG&E's refusal to negotiate a successor agreement with [Sacramento Municipal Utility District (SMUD)] to constitute undue discrimination, SMUD must demonstrate it is similarly situated to Western.”).

46. As with commenters' reliance on

Enron,

we find that commenters' reliance on

Alabama Power

is misplaced. The Commission is not determining whether a single rate imposed on two groups of customers may unduly discriminate against one of those groups. Instead, the Commission is promulgating a generic rule that amends the scheduling requirements of the

pro forma

OATT to remedy practices throughout the industry that may be causing jurisdictional rates to be excessive or unduly preferential. Accordingly, the task before the Commission is not comparing the impact of a concrete rate proposal on distinct and readily identifiable customers or classes. Rather, the Commission is broadly evaluating whether the

pro forma

OATT contains the appropriate set of requirements to ensure that rates for all customers remain just and reasonable and not unduly discriminatory. As in Order No. 890, the Commission is acting in part to remedy OATT provisions that may allow public utility transmission providers to treat some customers in an unduly discriminatory manner. Such an endeavor necessarily requires the Commission to take notice of the general developments in the electric industry in deciding what generic reforms may be needed to ensure that the

pro forma

OATT does not unduly discriminate against any one class of customers.

See Transmission Access Policy Study Group

FERC,

225

F.3d 667 (D.C. Cir. 2000) (TAPS) (affirming Order No. 888 rulemaking based on general findings, rejecting utility arguments that FERC must have substantial evidence and make specific factual findings);

Wisc. Gas Co.

FERC,

770 F.2d 1144 (affirming that Commission need not make individual findings regarding each affected entity but can rely on a broader record in promulgating rule of general applicability);

Associated Gas Distrib.

FERC,

824 F.2d 981 (affirming that the Commission is not required to have empirical data for all the propositions upon which its order depended before promulgating a rule).

47. In Order No. 890, the Commission recognized that the mix of generation resources on the system was changing and that not all generation resources were similarly situated.

In response, the Commission instituted reforms that recognized the unique nature of intermittent resources, tailoring certain requirements to the special circumstances presented by this type of resource.

We again recognize that VERs, by definition,

are not similarly situated to conventional, dispatchable generators and that reforms to the

pro forma

OATT are necessary to ensure that these resources are treated in a fair and not unduly discriminatory manner. Simply because VERs are not similarly situated in all respects to conventional, dispatchable generators, it does not follow, as Southern and EEI assert, that existing

pro forma

OATT provisions that place a disproportionate burden on VERs are just and reasonable.

The more frequent scheduling intervals required by this Final Rule will enable VERs, as well as other generators, to schedule transmission service accurately based on forecasted energy output. This will mitigate VERs' exposure to imbalance charges, while at the same time giving public utility transmission providers a better understanding of expected energy flows on their systems.

Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 5.

Id.

P 663 (requiring that generator imbalance provisions account for the special circumstances presented by intermittent generators).

See supra

note 1 (defining VER).

See Alabama Power,

684 F.2d at 23-24 (“It matters little that the affected customer groups may be in most respects similarly situated—that is, that they may require similar types of service at similar (even if varying) voltage levels. If the costs of providing service to one group are different from the costs of serving the other, the two groups are in one important respect quite dissimilar.”).

48. The Commission does not need to make specific findings with respect to each affected entity so long as the agency's factual determinations are reasonable.

As further discussed herein, the Final Rule amends the

pro forma

OATT in ways that will limit uncertainty and provide additional control over scheduling, which should reduce imbalance charges for all customers. The proposed reforms will further benefit customers and the market as a whole by providing increased flexibility and encouraging innovation and participation by new market participants.

While the Commission commenced this proceeding as a response to the significantly increasing penetration of VERs into the nation's generation portfolio, the Commission's purpose is not to favor VERs over other forms of generation (or demand) resources. Quite the contrary, a primary goal of this proceeding is to remove obstacles that can have a discriminatory impact on the ability of VERs to compete in the marketplace and that can otherwise result in unjust and unreasonable rates for all market participants.

TAPS, 225

F.3d at 688 (citing

Wisc. Gas Co.

FERC,

770 F.2d at 1158).

Cf.

Order No. 679,

Promoting Transmission Investment through Pricing Reform,

Order No. 679, FERC Stats. & Regs. ¶ 31,222, at PP 131, 176, 224,

order on reh'g,

Order No. 679-A, FERC Stats. & Regs. ¶ 31,236, at P 77 (2006),

order on reh'g,

Order No. 679-B, 119 FERC ¶ 61,062 (2007). The Commission does not authorize these measures to provide a unilateral benefit to transmission owners but rather to encourage the development of needed transmission, which has broader benefits to the market and consumers.

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 23.

49. Finally, in response to Southern, the Commission notes that it is not

asserting jurisdiction over the practice of power production forecasting in this Final Rule. Rather, the Commission is adopting changes to the

pro forma

LGIA to impose reporting requirements on interconnection customers whose generating facilities are VERs. As discussed in further detail later in this Final Rule, power production forecasting can be used by public utility transmission providers to significantly reduce operating costs associated with the integration of VERs interconnected to their systems.

However, the ability of public utility transmission providers to engage in power production forecasting may be limited without data from interconnected VERs. In order to facilitate a public utility transmission provider's use of power production forecasting to reduce its operating costs, the Commission is amending the requirements of the

pro forma

LGIA to impose a data reporting requirement as a condition of interconnection service for interconnection customers whose generating facilities are VERs.

See infra

§ IV.B.1 (Data Requirements).

50. The question then is whether the Commission has jurisdiction to condition the grant of interconnection service on the reporting of meteorological and outage data by interconnection customers whose generating facilities are VERs as a practice affecting rates subject to the Commission's jurisdiction under the FPA.

As the Commission explained in Order No. 2003, interconnection service is a component of open access transmission service, subject to the Commission's regulation under sections 205 and 206 of the FPA.

The reporting of meteorological and outage data by VER customers taking jurisdictional interconnection service has a direct affect on the ability of the public utility transmission provider to efficiently manage the VER integration through the development and deployment of power production forecasting. Failure to require the reporting of this data could limit the public utility transmission provider's ability to develop and deploy power production forecasts and, in turn, its attempts to efficiently commit or de-commit resources providing regulation reserves, potentially resulting in rates for reserve-related services that are unjust and unreasonable or unduly discriminatory. It is therefore reasonable for the Commission to conclude that it is within our jurisdiction to implement the data reporting requirements of this Final Rule as a condition of interconnection service.

See Cal. Indep. Sys. Oper.

FERC,

372 F.3d 395 (D.C. Cir. 2004).

Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at 12.

IV. Proposed Reforms

A. Intra-Hour Scheduling

51. The first of the two reforms adopted in this Final Rule relates to the intervals at which transmission customers may submit transmission schedules under the

pro forma

OATT. As discussed below, the Commission amends the

pro forma

OATT to provide all transmission customers the option of using more frequent transmission scheduling intervals within each operating hour, at 15-minute intervals. The Commission concludes this change to existing operational practices is necessary in order to ensure that charges for generator imbalance service under Schedule 9 of the

pro forma

OATT and for generator regulation service, as relevant, are just and reasonable and not unduly discriminatory.

1. Intra-Hour Scheduling Requirement

a. Commission Proposal

52. In the Proposed Rule, the Commission preliminarily found 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

pro forma

OATT. Specifically, the Commission preliminarily found 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 proposed to amend sections 13.8 and 14.6 of the

pro forma

OATT to provide transmission customers the option to schedule transmission service on an intra-hour basis, at intervals of 15 minutes. The Commission noted that its proposed reform would allow for intra-hour scheduling adjustments and that it did not propose changes to the hourly transmission service reservation provided in the OATT.

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 39 & n.89.

53. The Commission acknowledged in the Proposed Rule that a number of public utility transmission providers already have begun implementing intra-hour scheduling practices. The Commission stated that, while these individual reforms are important steps toward the efficient integration of VERs, it believed that it also is important to establish 15-minute scheduling periods as the default scheduling process. At the same time, the Commission acknowledged arguments that regional differences should be respected when developing an implementation process and that any Commission action should not negatively affect ongoing industry efforts. In that regard, the Commission sought comment on the best approach for implementing the proposed intra-hour scheduling reforms. The Commission recognized that an optimal implementation approach should support ongoing industry efforts and may consider regional differences, such as the amount of VERs present in that region. In proposing implementation approaches, the Commission encouraged commenters to consider any impacts on transmission customers scheduling across multiple systems and whether these impacts diminish the benefits of implementing intra-hour scheduling.

Id.

PP 42-43.

54. To understand more fully the modifications that this proposed reform may require, the Commission sought comment on the specific hardware, software, and personnel changes that are necessary to implement intra-hour scheduling. The Commission further inquired as to whether there would be any additional impacts on relatively small public utility transmission providers, and how to best facilitate this reform for small public utility transmission providers.

b. Comments

i. Obligation to Offer Intra-Hour Scheduling

55. A number of commenters support the Commission's proposal to require public utility transmission providers to offer intra-hour scheduling,

although some seek clarifications or modifications of the proposal. Additionally, commenters disagree as to the appropriate period of time for submitting intra-hour schedules. These commenters generally agree that intra-hour scheduling would enable transmission customers to align transmission schedules with actual generation output more effectively, reduce the need for transmission providers to carry expensive operating

reserves, and provide for greater system flexibility by utilizing available resources in a more efficient manner.

E.g.,

A123; Alstom Grid; ACSF; Argonne National Lab; BP Energy; California ISO; CESA; CMUA; CEERT; Center for Rural Affairs; Clean Line; CGC; Defenders of Wildlife; Environmental Defense Fund; EPSA; Exelon; First Wind; FriiPwr; Independent Power Producers Coalition—West; Independent Energy Producers; ITC Companies; NextEra; NaturEner; Organization of Midwest ISO States; Oregon and New Mexico PUC; Public Interest Organizations; Powerex; SWEA; Tacoma Power; Tres Amigas; TVA; Vestas; Viridity Energy; Vote Solar; Western Grid; Xcel.

56. For example, EPSA states that the option of 15-minute scheduling would expand the availability of flexible generation resources and demand response resources to provide additional liquidity and consistency in the market. Exelon argues that implementing intra-hour scheduling will reduce supply-side uncertainty, which should allow resources to be more optimally selected and allocated than otherwise would be the case. Powerex contends that shorter scheduling intervals would allow the use of more accurate forecasts that are closer to the operating time-frame. Joined by CEERT and others, Powerex argues that intra-hour scheduling would increase transmission system flexibility and efficiency, providing grid operators with more options for scheduling resources during each hour and decreasing the need for (and costs of) ancillary services needed for reliable integration of VERs.

The Center for Rural Affairs asserts that making intra-hour scheduling available is essential for public utility transmission providers and balancing authorities seeking to provide system balance with increasing generation from VERs.

E.g.,

CEERT; Powerex; Public Interest Organizations; Vestas.

57. While acknowledging that some stakeholders in this proceeding oppose the mandatory nature of the Commission's proposal, disagree about scheduling costs, and question the reliability impacts of the proposed reforms, Public Interest Organizations state that almost all stakeholders have acknowledged that intra-hour scheduling does improve scheduling accuracy and decrease the need for energy imbalance services. Public Interest Organizations, joined by Environmental Defense Fund and Argonne National Lab, contend that intra-hour scheduling, as compared to hourly scheduling protocols, allows for a more accurate prediction of the variable generation that can be delivered within the market interval, reducing the need to procure expensive regulation or energy imbalance services.

NaturEner agrees, arguing that shorter scheduling intervals would allow for more frequent generation adjustments, thus, decreasing the negative impacts on both the transmission system and the grid from frequent generation disruptions. Iberdrola similarly contends that moving toward smaller intra-hour scheduling intervals will provide incentives for more complete and efficient scheduling practices and eliminate other outdated and discriminatory operating practices.

E.g.,

Argonne National Lab; Environmental Defense Fund; Public Interest Organizations.

58. California ISO states that continuing to require resources to match hourly transmission schedules would perpetuate inefficient and burdensome operational requirements. Tres Amigas contends that current scheduling practices have been associated with underutilized transmission assets and sub-optimal operating practices resulting in inefficient curtailment of generation. BP Energy asserts that 15-minute scheduling intervals will increase the ability of a transmission customer scheduling energy from a VER to manage the scheduled input and, therefore, its imbalance costs. Vestas notes that all generators, regardless of fuel type, will be able to track their schedules more closely with actual levels of production as a result of intra-hour scheduling. Vestas explains that, if a large fossil-fueled resource suffers an outage or derate within an hour, the ability to change its schedule earlier than the next clock hour can provide significant benefits to both the generator and the transmission system operator. Clean Line contends that intra-hour scheduling is likely to have benefits independent of variable generation integration, stating that sub-hourly variations in load could be managed in a more cost-effective manner. Also, A123 contends that shorter scheduling intervals will help OATT markets incorporate the benefits of high-ramp, limited energy resources like storage.

A ramp rate is the rate, expressed in megawatts per minute, that a resources changes its output.

See

NERC Glossary of Terms, available online at

http://www.nerc.com/files/Glossary_of_Terms.pdf

59. However, other commenters oppose mandatory intra-hour scheduling, arguing generally that current scheduling practices are neither preferential nor unduly discriminatory.

For example, ELCON states that the Commission's proposals are costly measures that would apply preferentially to just one class of generation—VERs—in order to address discrimination that does not actually exist. Some commenters argue that further study of the need for intra-hour scheduling should be undertaken prior to mandating the practice. Several of these commenters assert that the Commission should not require the implementation of 15-minute intra-hour scheduling until certain impacts are better understood.

LADWP submits that intra-hour scheduling should not be implemented until it has been fully vetted and researched to assess operational capabilities and coordination.

E.g.,

ELCON; Midwest ISO; NV Energy; Southern.

E.g.,

California PUC; LADWP; NorthWestern; NV Energy; Pacific Gas & Electric.

60. Some commenters argue that the Commission's proposed reform may not lead to a reduction in aggregate reserve costs. These commenters contend that the implementation of intra-hour scheduling does not negate the inherent variability of VERs and, therefore, the cost of providing balancing services is merely shifted, rather than mitigated, by intra-hour scheduling.

For example, Avista explains that, while the host balancing authority will provide a reduced amount of balancing reserves within each scheduling period, a significant portion of this variability is being covered by the sink balancing authority or the load serving entity (LSE). Avista contends the sink balancing authority or LSE will incur increased balancing costs to follow the fluctuating VER schedule against a relatively more constant load, thereby shifting the cost of managing that variability as opposed to creating substantial cost savings through intra-hour scheduling. If the host balancing authority area and the sink balancing authority area are the same, Avista argues that no cost savings or reduction in reserves is accomplished by the proposed scheduling reforms. Iberdrola argues that implementing intra-hour scheduling absent a market for dispatchable resources to manage variability could potentially be more harmful than helpful to VER integration. Duke argues that, due to the inherent variability of VERs, more regulating reserves will be needed regardless of the scheduling interval. While operating experience may diminish the need for regulating reserves over time, Duke contends that the level of regulating reserves will ultimately be maintained at a higher level than required today. M-S-R Public Power Agency encourages the Commission to consider the effectiveness of reducing overall intermittency management obligations further before implementing an intra-hour scheduling reform.

E.g.,

Avista; Bonneville Power; M-S-R Public Power Agency; Xcel.

61. With regard to the appropriate time interval for intra-hour scheduling, a number of commenters support the Commission's proposal to require public utility transmission providers to offer intra-hour scheduling at 15-minute intervals.

Many of these commenters

agree that a scheduling interval of 15-minutes or shorter provides a number of benefits such as lowering the costs related to integrating VERs into the market and operational benefits. Argonne National Lab states that requiring transmission providers to schedule resources with a frequency of at least every 15 minutes would provide benefits to all supply and demand resources in the power system, not only VERs. Several commenters argue that scheduling in 15-minute intervals would reduce imbalance charges through more accurate schedules.

EPSA notes that the proposed 15-minute scheduling interval is consistent with NERC recommendations for achieving greater flexibility while meeting relevant reliability requirements.

Exelon asserts that 15-minute scheduling is an industry best practice and that the Commission should set a deadline by which all transmission providers must conform.

E.g.,

A123; Alstom Grid; ACSF; Argonne National Lab; BP Companies; CESA; CEERT; Center for Rural Affairs; Clean Line; CGC; Defenders of

Wildlife; Environmental Defense Fund; EPSA; Exelon; First Wind; Independent Energy Producers; ITC Companies; NaturEner; Organization of Midwest ISO States; Oregon & New Mexico PUC; Powerex; Public Interest Organizations; SWEA; Tres Amigas; Viridity Energy; Vote Solar; Western Grid; Xcel.

E.g.,

BP Energy; CEERT; CGC; Defenders of Wildlife; Duke; NextEra; Public Interest Organizations; SEIA; Vestas; Xcel.

EPSA (citing NERC April 12, 2010 Response to NOI at 17-18).

62. Vestas acknowledges that a shortened scheduling interval must strike a balance between the benefits of increased certainty and reduced variability resulting from customers' ability to more closely match their schedules with their anticipated output and any increased complexity and technical issues that could result if the scheduling interval is too short. Vestas contends that a 15-minute scheduling window provides a reasonable compromise between the current hour and the even shorter 5-minute intervals utilized in certain RTO markets. Oregon & New Mexico PUC agree that as more wind and solar generation are integrated into the system, shorter intra-hour intervals will generate greater cost savings than longer intervals. Oregon & New Mexico PUC urge the Commission to adopt a minimum standard for transmission scheduling at 15-minute intervals to focus industry efforts on implementing a consistent standard rather than debating the appropriate interval.

63. Some commenters are concerned that the proposed 15-minute scheduling interval is too long.

While supportive of 15-minute scheduling as an interim step, several commenters recommend that the Commission require public utility transmission providers to move to shorter scheduling intervals.

RenewElec asserts that 15-minute scheduling may not be sufficient for the integration of large amounts of VERs. As an option for increasing flexibility without decreasing the 15-minute scheduling period, SEIA asks the Commission to clarify that generators may submit 15-minute schedules with different output levels at the beginning and end of the 15-minute period to reflect anticipated ramps to manage the variations in diurnal ramping of solar resources. Vote Solar echoes the concerns of SEIA with regard to solar diurnal ramping and argues for scheduling intervals more granular than 15-minutes to accommodate wide-area balancing. Vote Solar recommends that the Commission additionally require a 5-minute intertie scheduling interval. However, EEI cautions that if the Commission decides to move forward with the rule as proposed, the scheduling interval should be no less than 15 minutes as it may undermine the reliable operation of the system.

E.g.,

Environmental Defense Fund; FriiPower; Independent Power Producers Coalition-West; RenewElec; SEIA; Vestas.

E.g.,

Environmental Defense Fund; Independent Power Producers Coalition-West; RenewElec.

64. Other commenters argue that the proposed 15-minute scheduling interval is too short.

Several commenters recommend an initial 30-minute intra-hour scheduling interval to coincide with current regional initiatives or as a general first step.

Some commenters argue that the Commission should use the output of ongoing regional initiatives to determine whether a 15-minute scheduling interval is necessary, or whether another mechanism is the desired method to reduce VER integration costs.

EEI states that, if there is no demand for intra-hour scheduling, investments to implement 15-minute scheduling would be unnecessary. NorthWestern expresses uncertainty as to whether 15-minute scheduling would provide benefits greater than those achieved through 30-minute scheduling. Southern California Edison suggests that a 30-minute scheduling interval is sufficient as it can capture forecast error reductions, align with the commitment capabilities of most integrating resources, and reduce the need for additional administrative overhead. Iberdrola recommends that the Commission allow public utility transmission providers to provide intra-hour schedules at 30-minute intervals as an interim step to participation in an energy imbalance market.

E.g.

, LADWP; Montana PSC; NV Energy; Puget.

E.g.

, Bonneville Power; California ISO; California PUC; CMUA; Montana PSC; NorthWestern; NV Energy; Snohomish County PUD; Southern California Edison; WUTC.

E.g.

, Bonneville Power; California PUC; CMUA; FirstEnergy; NorthWestern; Snohomish County PUD; Southern California Edison.

65. Some commenters contend that a 15-minute scheduling interval does not support the standard 20-minute generator/scheduling ramp rate in the West.

Tacoma Power explains that continuing to use 20-minute ramps would create interface problems with the receipt of schedules on a 15-minute interval. Bonneville Power similarly argues that scheduling on a 15-minute interval would result in almost continuous ramping in a way that 30-minute scheduling does not, and that the resulting reduction in dynamic transfer capability could preclude implementation of other options for reducing VER integration costs. WestConnect asserts that this may result in a disparity in the accurate scheduling of VERs and the system operator's ability to efficiently integrate VERs under restricted ramping intervals.

E.g.

, LADWP; NorthWestern; PNW Parties; Tacoma Power; WestConnect.

66. Bonneville Power and Xcel request clarification that “intra-hour scheduling adjustments” include both adjustments to existing schedules and the submission of new schedules.

MidAmerican requests clarification as to whether intra-hour scheduling is intended to be available only within the current hour or also in future hours.

Bonneville Power; Xcel.

ii. Consistency in Scheduling Requirements

67. Commenters differ regarding whether the Commission should adopt a consistent intra-hour scheduling requirement for all transmission providers under the

pro forma

OATT. If the Commission decides to move forward with its proposal, EEI recommends that the Commission require a uniform, consistent scheduling interval throughout each interconnection. EEI contends that this will allow for the development of uniform and consistent intervals in reliability standards and business practices and also promote accuracy of results. A number of other commenters agree that consistent scheduling intervals are needed in order for intra-hour scheduling to occur across balancing authority areas.

For

example, NorthWestern and Southern contend that, unless all public utility transmission providers within an interconnection are required to comply with the same intra-hour scheduling interval, intra-hour scheduling may erode a utility's ability to maintain reliability.

E.g.

, Argonne National Lab; EEI; Iberdrola; Independent Power Producers Coalition-West; NaturEner; NorthWestern; NRECA; Oregon & New Mexico PUC; Public Interest Organizations; Puget;

Southern California Edison; Southern; and Tres Amigas.

68. Public Interest Organizations agree that there is a need to apply consistent scheduling obligations across the country in order to avoid undue discrimination against VERs and argue that the benefits of 15-minute intra-hour scheduling will apply throughout the system, not just to VERs. If the Commission decides to allow for a public utility transmission provider to propose variations to 15-minute scheduling, Public Interest Organizations suggest that the entity be required to demonstrate why a variation is necessary and show that the proposed alternative will be equally effective or superior to the Commission's proposal. NextEra points out that the arguments favoring regional variations in scheduling requirements ignore the fact that many regions have no overall regional body or authority with sufficient ability to ensure consistency in resolving issues regarding VER integration. NextEra submits that the Commission has ultimate responsibility to ensure that market rules are just and reasonable, and that the Commission cannot delegate its responsibility to states, regions, or public utilities. Tres Amigas requests that the Commission clarify that intra-hour scheduling will apply to all generation scheduled on the bulk transmission system; inter- and intra-balancing authority transactions, and point-to-point, network, or native load service. Tres Amigas states that inconsistent transmission scheduling periods will lead to inefficient and/or discriminatory use of the transmission system.

69. Many commenters contend that the Commission should afford public utility transmission providers the flexibility to determine how best to implement intra-hour scheduling in their region. These commenters ask the Commission to acknowledge that region-specific scheduling practices may be appropriate in light of system circumstances and market designs.

Several of these commenters note that there are regional efforts and pilot programs underway that are aimed at efficiently managing the integration of VERs and providing an opportunity for intra-hour scheduling.

These commenters generally contend that the Commission should support and not undermine such regional initiatives. Examples of regional initiatives identified by commenters include the Joint Initiative,

the WECC Efficient Dispatch Toolkit,

and a pilot between Bonneville Power and the California ISO to evaluate the use of intra-hour scheduling on the California-Oregon Intertie.

Several commenters suggest that the Commission should conduct technical conferences to investigate the relative merits of these and alternative approaches prior to imposing a uniform national mandate.

E.g.

, Avista; Bonneville Power; California ISO; CMUA; California PUC; Detroit Edison; Dominion; EEI; FirstEnergy; Grant PUD; Idaho Power; Independent Power Producers Coalition-West; ISO/RTO Council; Midwest ISO; Montana PSC; National Grid; NorthWestern; NRECA; New York ISO; NV Energy; PJM; PNW Parties; Public Power Council; Puget; SMUD; Southern; Tacoma Power; WUTC; WestConnect.

E.g.

, Avista; Bonneville Power; Business Council; California ISO; California PUC; CESA; CMUA; EEI; Idaho Power; Joint Initiative; Montana PSC; National Grid; NorthWestern; NV Energy; PNW Parties; Puget; SMUD; WestConnect.

The Joint Initiative is a consensual, collaborative effort within the Western Interconnection to develop high-value and cost-effective regional products, identified through a stakeholder process, for implementation by interested parties. It is jointly sponsored by Columbia Grid, Northern Tier Transmission Group, and WestConnect. Joint Initiative at 1-3. Step one of the Products and Services Strike Team intra-hour scheduling initiative began in July 2011 with the scheduling of transmission in half hour increments. Step two includes broader application of intra-hour scheduling and scheduling in finer increments (15 or 20 minutes) only after evaluation that this step is necessary.

The WECC Efficient Dispatch Toolkit contains: (1) An enhanced curtailment calculator that will aid in managing flows across constrained paths; and (2) an energy imbalance market that will efficiently dispatch resources in response to imbalance.

This pilot program is intended to facilitate the export of wind resources located in Bonneville Power's Balancing Authority into the California ISO. The pilot will use dynamic e-tagging and communication to facilitate intra-hour schedule changes, beginning with a 30-minute scheduling interval.

E.g.

, California ISO; Grays Harbor PUD; Pacific Gas & Electric; SMUD; Snohomish County PUD.

70. Some commenters express concern that a Commission mandate may detrimentally affect current regional efforts by diverting resources from or discouraging participation in voluntary regional initiatives by both jurisdictional and non-jurisdictional entities.

100

Bonneville Power and CMUA suggest that ongoing initiatives may provide the Commission with real-world data and alternative options to reach the Commission's stated goals. In order to support ongoing regional initiatives, Pacific Gas & Electric recommends that the Commission not implement 15-minute scheduling until regional initiatives have been given a reasonable amount of time to come to an end. Grant PUD argues that 20-30 minute scheduling intervals appear to be sufficient for the Northwest region of the country and that the Commission should allow this to be considered a “regional practice.”

101

In addition, NRECA argues that the Commission should afford public utility transmission providers an opportunity to demonstrate that existing practices or practices under development are or will be consistent with or superior to the Commission's proposed reforms.

100

E.g.

, Avista; Bonneville Power; California PUC; EEI; Idaho Power; National Grid; NorthWestern; NRECA; NV Energy; PNW Parties.

101

Grant PUD at 4.

71. Some commenters stress the need for regional flexibility because, in their view, intra-hour scheduling may not be the right decision for everyone.

102

For example, LADWP asserts that the Proposed Rule is ill-timed, and that intra-hour scheduling may not be necessary in regions where the existing generation portfolio provides sufficient flexibility to integrate a fixed percentage of VER penetration reliably. Southwestern explains that, as a federal agency operating under a Congressional statutory mandate, the Administration may not be able to implement intra-hour scheduling as this may impact the purposes of the Corps projects such as flood control, hydropower, navigation, fish and wildlife, and recreation. If the Commission adopts the Proposed Rule, NRECA urges the Commission to permit public utility transmission providers to seek a waiver from implementing intra-hour scheduling until the entity receives a request to schedule intra-hour.

102

E.g.

, ISO/RTO Council; NorthWestern; Pacific Gas & Electric; PNW Parties; Public Power Council; Puget.

72. A number of commenters question the applicability of the proposed intra-hour scheduling requirements in regions with RTOs/ISOs, arguing that these markets already provide for system flexibility that is consistent with or superior to the intra-hour scheduling protocol proposed by the Commission.

103

Business Council suggests that the Commission should focus its attention on areas where rapid spot energy and ancillary service markets do not exist, particularly non-RTO/ISO areas that are experiencing significant renewable energy penetration. ISO/RTO Council asks the Commission to recognize that different regions currently provide varying levels of flexibility to VERs through different

systems and market mechanisms, suggesting that the Commission craft the Final Rule in a manner that allows transmission providers to work with their stakeholders to develop solutions that work for their region. FirstEnergy asserts that each RTO and ISO, through its stakeholder process, should be given the opportunity to evaluate the potential need for, and benefits and costs associated with, intra-hour scheduling. Sunflower and Mid-Kansas similarly argue that the Final Rule should recognize the differences between organized markets and not group them with non-RTO public utility transmission providers. Environmental Defense Fund asserts that, because some RTOs and/or balancing authorities have begun to implement regional scheduling reforms, the Commission should avoid imposing duplicative requirements or obstructing such efforts.

103

E.g.

, AWEA; California ISO; California PUC; Detroit Edison; Iberdrola; ISO New England; Massachusetts DPU; Midwest ISO; PJM; Public Interest Organizations; RENEW; Sunflower and Mid-Kansas; Western Farmers.

73. Some commenters suggest that the Commission clarify that its proposed intra-hour scheduling reforms apply only to RTOs and ISOs in the context of transactions between balancing authorities.

104

However, National Grid cautions the Commission against overly-prescriptive requirements for scheduling between regions and asks for clarification that public utility transmission providers are permitted to pursue other scheduling improvements for cross border transactions and inter-tie scheduling. National Grid notes that New York ISO and ISO New England are already working on solutions to improve interregional interchange scheduling. ISO/RTO Council states that accelerated scheduling changes may negatively affect RTO and ISO interchanges with non-market areas, as those smaller areas may be unable to keep up with an RTO or ISO scheduling within the hour.

104

E.g.

, AWEA; Iberdrola; Public Interest Organizations; and RENEW.

74. Many commenters express concern regarding the potential for seams issues, particularly with transmission providers that are not subject to the Commission's ratemaking jurisdiction under sections 205 and 206 of the FPA.

105

Some commenters argue that, for a generator to submit a 15-minute schedule, all balancing authorities involved in the transmission chain must approve the tag or it will be rejected.

106

While the source balancing authority may approve the schedule, PNW Parties explain that the schedule may be denied in the adjacent balancing area if the same intra-hour scheduling procedures are not used, irrespective of the jurisdictional status of the transmission providers involved. Xcel suggests that, in areas where the balancing authority and transmission provider are separate entities, explicit guidance may be needed in order for a balancing authority to accept intra-hour schedules from a transmission provider. Xcel recommends that the Commission place responsibility on the balancing authority to approve intra-hour scheduling changes made in accordance with an approved tariff.

105

E.g.

, Avista; California ISO; Duke; EEI; Idaho Power; MidAmerican; NorthWestern; NV Energy; PNW Parties; Puget; Southern California Edison; Southern; Tres Amigas; WUTC.

106

E.g.

, PNW Parties; Puget; WUTC.

75. Additionally, these commenters question how beneficial intra-hour scheduling will be in the absence of consistent and compatible scheduling intervals among jurisdictional and non-jurisdictional entities.

107

Puget states that, while it has offered intra-hour scheduling since December 2009, its customers have scheduled few transactions due to the lack of conforming scheduling practices in neighboring non-jurisdictional utilities. If transmission customers are unable to schedule across seams at 15-minute intervals, Puget argues that jurisdictional utilities will receive little benefit from the required software, personnel and accounting changes needed to facilitate 15-minute scheduling. Idaho Power submits that seams issues created by different intervals in adjacent systems may ultimately lead to an increase in the costs of VER integration. WUTC asserts that for jurisdictional entities to implement intra-hour scheduling unilaterally would be economically unproductive and may disrupt reliability functions. Idaho Power and EEI similarly contend that seams issues may affect reliability.

107

E.g.

, Avista; California ISO; Duke; EEI; Idaho Power; NorthWestern; NV Energy; PNW Parties; Puget; Southern California Edison; Southern; Tres Amigas; WUTC.

76. EEI suggests that the Commission not require public utility transmission providers to provide intra-hour scheduling prior to an evaluation of the impacts on coordination between and among jurisdictional and non-jurisdictional entities. California ISO contends the parties in the West should continue with coordinated efforts to find reasonable solutions that can be implemented without placing an undue burden on neighboring parties. California PUC recommends that the Commission allow sufficient flexibility for public utility transmission providers to determine the most efficient way to support intra-hour scheduling across interties.

77. Snohomish County PUD and Grays Harbor PUD request that the Commission evaluate whether existing supply arrangements with Bonneville Power, referred to as “slice” contracts, allow for intra-hour scheduling before adopting the proposed requirements. Snohomish County PUD explains that these contracts allow customers to pay a fixed percentage of Bonneville Power's costs and, in turn, receive an equal percentage of output, thereby taking advantage of the flexibility of the federal system. However, Snohomish County PUD and Grays Harbor PUD state that these “slice” contracts limit customers to hourly scheduling. Snohomish County PUD is concerned that it and other similarly situated transmission providers may be unable to implement 15-minute scheduling. Snohomish County PUD contends that, as a result, it and others may have to acquire additional reserves in order to balance wind resources, in effect paying twice for the same capacity and scheduling flexibility. Snohomish County PUD asserts that this issue has already arisen in Bonneville Power's ongoing efforts to develop intra-hour scheduling at 30-minute intervals.

iii. Cost to Implement Intra-Hour Scheduling

78. A number of parties address the potential costs of implementing the Commission's proposed intra-hour scheduling requirement. Exelon states that there likely will be some development and ongoing administrative costs, such as modifying Open Access Same-Time Information System (OASIS) and interchange ramp software and additional staff to evaluate and confirm more frequent scheduling changes, but does not expect that such costs would be excessive. Tres Amigas contends that the incremental costs of providing intra-hour scheduling will be very modest. NaturEner argues that many transmission providers could implement intra-hour scheduling with existing staff and equipment but that, even if that is not the case, entities should be incentivized or required to automate or otherwise update their system as it would expedite the scheduling and transmission approval system. Independent Power Producers Coalition-West contends that increased automation and staffing would enhance the ability of a balancing authority to schedule at shorter intervals and achieve further integration of VERs.

79. Other commenters state that the cost of implementing intra-hour

scheduling may be significant.

108

EEI and PNW Parties assert that intra-hour scheduling will affect many activities and systems, causing transmission providers in some regions to institute hardware, software, and personnel changes. For example, EEI and PNW Parties contend that changes will be required to numerous computer systems, such as energy management systems, scheduling applications, and automated checkout systems such as the WECC Interchange Tool, and also that certain practices not currently automated will have to be automated. EEI and PNW Parties note that staff would need to be trained on these new tools and additional staff would be required to process the expanded scheduling information being received. NRECA contends that the costs will be driven largely by software and personnel changes, rather than hardware investments, but that it is difficult to estimate with precision what software changes would be needed without knowing what measures NAESB will adopt in order to standardize the new scheduling regime.

108

E.g.

, Avista; Bonneville Power; EEI; Grant PUD; MidAmerican; NRECA; NorthWestern; PNW Parties; Puget; Snohomish PUD; Southern California Edison; Southwestern; Tacoma Power; TVA.

80. NextEra explains that several steps will need to be taken in order to implement 15-minute scheduling but contends that the cost impacts are uncertain. NextEra provides that actions to implement intra-hour scheduling include potential modifications to both internal and external software packages. According to NextEra, these software programs, providing functions such as eTagging, accounting, and billing, will need to be harmonized across vendors. Additionally, NextEra contends that it is unclear whether existing systems would need to be replaced or modified, or whether functions currently being performed manually would need to be automated.

81. Some transmission providers estimate the level of investment and staffing changes that would be required to implement 15-minute scheduling on their system, although most discuss such estimates in the context of a broader range of activities that they believe may be intended or implicated by the implementation of 15-minute scheduling.

109

For example, Avista states that it would need to hire and train around-the-clock personnel at an estimated cost of $1.2 million per year to implement “an approach that will allow for schedule adjustments

and

imbalance settlements in 15 minute periods.”

110

MidAmerican estimates approximately $1.0 million in staff costs to implement “similar intervals for balancing activities and interchange” and, to the extent energy management and accounting systems must be changed, up to $2.0-2.3 million in infrastructure upgrades.

111

Bonneville Power also contends that it would need an additional 24x7 position, staffed by six full-time employees, to manage what it characterizes as the risks created by 15-minute scheduling, including the redesign of imbalance service and increased use of special protection schemes.

109

E.g.

, Avista; Bonneville Power; Grant PUD; MidAmerican; NorthWestern; PNW Parties; Puget; Snohomish County PUD; Southwestern; Tacoma Power; TVA.

110

Avista at 12, 14 (emphasis in original).

111

MidAmerican at 14.

82. NRECA notes that the relative cost impact of implementing intra-hour scheduling will depend on a number of factors, such as the size of the system and how widely intra-hour scheduling is utilized. Although agreeing that the costs may be significant, NRECA states that costs are not expected to be extraordinary and can be mitigated through proper design and implementation. NRECA estimates implementation costs under a range of scenarios. Assuming hourly schedules at a 15-minute interval used only by VERs, NRECA anticipates the need for software modifications in the range of $50,000 per company, but notes that some of its members have incurred expenses in the range of $250,000 annually for software licensing and maintenance related to scheduling and energy accounting software upgrades. If hourly schedules at a 15-minute interval are widely used by transmission customers, NRECA estimates a minimum of one additional 24x7 shift, resulting in approximately $1.0 million of staffing costs, and potentially two 24x7 positions depending on the size of the transmission provider. Finally, if hourly schedules at a 15-minute interval are settled on a 15-minute basis, NRECA estimates an additional $250,000 to $300,000 for additional “back room” staff to settle 15-minute schedules, interchange and deviation accounts.

83. Bonneville Power contends that many of the short-term costs associated with 15-minute scheduling would not be incurred to implement scheduling on 30-minute intervals. Bonneville Power states that it is currently updating systems and work processes to implement 30-minute scheduling in association with regional initiatives and that it believes the changes, resources, and system impacts associated with the implementation of scheduling at a 30-minute interval will be relatively modest compared to what would be required to implement 15-minute scheduling. Bonneville Power asserts that the systems, transmission upgrades, and resources required to accommodate the increasingly dynamic movements of power across the interconnection under 15-minute scheduling would not be required under 30-minute scheduling. Tacoma Power argues that it will determine the level of automation needed for 30-minute scheduling based on the experience it gains during implementation of the Joint Initiative intra-hour program, but that implementation of 15-minute scheduling intervals as discussed in the Proposed Rule would require immediate automation of all the processes for Tacoma Power to have any market presence.

iv. Requests for Additional Requirements

84. Some commenters contend that transmission customers should be encouraged or required to submit intra-hour schedules, arguing that the Commission's objectives of lowering reserve costs can be reached only if intra-hour scheduling is utilized in a consistent and predictable manner.

112

Bonneville Power argues that mandatory intra-hour scheduling is necessary to achieve the reduction in reserve requirements of 80 percent cited in its 2008 study.

113

Idaho Power and PNW Parties contend that VERs generally have a strong financial incentive to maximize energy output and, therefore, may schedule for a full hour to maximize benefits regardless of the availability of 15-minute scheduling. WUTC recommends that the Commission couple the implementation of intra-hour scheduling with measures to mitigate over-scheduling by VERs, particularly when market conditions are favorable for over-scheduling.

112

E.g.

, Bonneville Power; EEI; Idaho Power; MidAmerican; NorthWestern; Puget; PNW Parties; WUTC.

113

Bonneville Power (citing Bart McManus,

Large Wind Integration Challenges and Solutions for Operations/System Reliability

(2008). Bonneville Power clarifies that, in the study, mandatory 10-minute scheduling on a 10-minute persistence basis reduced the reserve requirements in the BPA region by 80 percent. Bonneville Power also clarifies that this reduction only applies to the source Balancing Authority, not the sink Balancing Authority).

85. Others recommend that the Commission provide incentives to use intra-hour scheduling by eliminating the exemption of VERs from third-tier generator imbalance penalties in Schedule 9 of the

pro forma

OATT, which they argue would no longer be just and reasonable given the

Commission's proposed reforms.

114

In addition to eliminating the exemption from third-tier generation imbalance penalties, MidAmerican suggests that an additional imbalance penalty tier be created for any transmission customer that consistently fails to adjust schedules on an intra-hour basis and creates significant variability. Avista recommends that the Commission allow transmission providers to impose appropriate penalties and recover the true costs of providing intra-hour schedules from VERs that continue to schedule on an hourly basis.

114

E.g.

, Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.

86. Several commenters argue that intra-hour scheduling may not achieve its intended benefits without additional reforms to augment intra-hour scheduling practices.

115

Some of these commenters assert that the Commission should allow a public utility transmission provider the flexibility to revise its energy imbalance settlement periods to align with any intra-hour scheduling interval.

116

Southern contends that this will allow a public utility transmission provider to offer appropriate incentives to customers to follow a given schedule and limit the potential for exposure to uncompensated risks.

115

E.g.

, Avista; AWEA; RenewElec; Vote Solar.

116

E.g.

, EEI; Duke; Idaho Power; Southern.

87. However, Avista states that there are positives and negatives to either maintaining hourly settlement with intra-hour scheduling or modifying settlement intervals to coincide with intra-hour scheduling intervals. Avista asserts that conforming intra-hour schedules and imbalance settlement at 15-minute increments for all transmission schedules would result in alignment of scheduling and imbalance billing for all transactions and reduce gaming potential. Avista argues that the potential for gaming by transmission customers through the overcorrection of schedules in order to minimize imbalance charges may require a public utility transmission provider to carry regulation reserves in excess of what is needed. Midwest ISO agrees, citing a report from its Independent Market Monitor indicating that large changes in Net Scheduled Interchange caused by 15-minute intra-hour scheduling could lead to price volatility and negative operational impacts.

117

Avista and Midwest ISO further state that conforming imbalance settlement with intra-hour schedules may require substantial and potentially costly office system changes, additional operations staff, and other costs incurred through the communication, metering, and storage of all customer data at 15-minute increments.

117

Midwest ISO (Potomac Economics, 2008

State of the Market Report for the Midwest ISO,

Docket No. ZZ09-4-000 at 169 [141] (June 21, 2009)).

88. Some commenters contend that intra-hour scheduling only governs the scheduling of flows on the transmission system and, by itself, does not necessarily affect the frequency with which generators are dispatched.

118

AWEA and Invenergy Wind agree that a transition to sub-hourly dispatch is the key for increasing the flexibility of the power system and for reducing the amount of reserves that must be held, which in turn will reduce costs for consumers and enable cost effective integration of VERs. Commenters recommend that the Commission require public utility transmission providers to implement a sub-hourly, real-time energy exchange that provides automated generation dispatch (such as an Efficient Dispatch Toolkit or the Energy Imbalance Market as adopted by the Southwest Power Pool and currently being studied in WECC). In AWEA's view, a market for sub-hourly energy would allow for netting of sub-hourly deviations and would provide price signals to incent greater sub-hourly flexibility.

118

E.g.

, AWEA; CEERT; Invenergy Wind.

89. AWEA acknowledges that changes to dispatch protocols and expansion of market options are being considered in regional efforts, but argues that progress is uncertain and unlikely to come to fruition in the near term. Iberdrola argues that intra-hour scheduling must be combined with intra-hour dispatch or market purchases to achieve the Commission's goals. Oregon and New Mexico PUC recommend that the Commission encourage reforms such as an Energy Imbalance Market or 15-minute calculations of available transmission capability (ATC) as a complement to intra-hour scheduling. However, Bonneville Power suggests distinguishing between intra-hour scheduling outside of a market region and intra-hour dispatch in an organized market, arguing that the costs and benefits of each may be dramatically different. Bonneville Power explains that the resources devoted to implementing 15-minute scheduling may be better used to pursue the development of an organized market with frequent dispatch intervals.

90. Some commenters assert that the Commission should consider changes to other aspects of electricity markets to facilitate intra-hour scheduling.

119

Invenergy Wind contends that consistent timeframes across all transmission and generation functions may lead to more efficient use of transmission capacity, regulation, and other ancillary services. American Clean Skies explains that the technology necessary to schedule transmission in 15-minute increments will also allow for scheduling reforms in the day-ahead market and the unit commitment process and, therefore, the Commission should require 15-minute scheduling reforms in these areas as well. However, PJM asserts that real-time control issues do not exist day-ahead and, therefore, the Commission need not consider reforms to the day-ahead market.

119

E.g.,

American Clean Skies; Invenergy Wind.

c. Commission Determination

91. The Commission concludes that it is appropriate to act at this time to adopt the scheduling reforms set forth in the Proposed Rule. Specifically, the Commission amends the

pro forma

OATT to provide all transmission customers the option of using more frequent transmission scheduling intervals within each operating hour, at 15-minute intervals. Our actions in this Final Rule will ensure that charges for generator imbalance service under Schedule 9 of the

pro forma

OATT and for other ancillary services through which reserve-related costs are recovered are just and reasonable and are not unduly discriminatory.

120

In section IV.C (Generator Regulation Service Capacity)

infra,

the Commission acknowledges that a range of capacity services could be used by public utility transmission providers to recover reserve-related costs.

92. As noted in the Proposed Rule, many

pro forma

OATT requirements, including hourly scheduling protocols, were developed at a time when virtually all generation on the system could be scheduled with relative precision.

121

As part of the Commission's regulatory responsibilities, we routinely review and, where appropriate, implement reforms to ensure the provision of service that remains just and reasonable and not unduly discriminatory. A similar review led the Commission in Order No. 890 to exempt VERs from the third-tier of generator imbalance penalties, given that VERs have a limited ability to accurately follow an hourly transmission schedule and, as a result, exposure to high imbalance penalties does not lessen their incentive to deviate from their schedule.

122

In this Final Rule, we take an additional step to allow transmission customers the flexibility to adjust their transmission

schedules, in advance of real-time, to reflect the variability of output in generation, more accurate power production forecasts to predict output, and other changes in load profiles and system conditions.

121

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 38.

122

Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 665.

93. Specifically, the Commission affirms the preliminary finding in the Proposed Rule that existing hourly scheduling protocols expose transmission customers to excessive or unduly discriminatory generator imbalance charges.

123

Under Schedule 9 of the

pro forma

OATT, generator imbalance charges are assessed on deviations between generator output and a delivery schedule over a single hour.

124

There is no requirement to provide customers the opportunity to adjust their transmission schedules within the hour to reflect changes in generator output. As a result, transmission customers have no ability under the

pro forma

OATT to mitigate Schedule 9 generator imbalance charges in situations when the transmission customer knows or believes that generation output will change within the hour. The Commission concludes that this lack of ability to update transmission schedules within the hour can cause charges for Schedule 9 generator imbalance service to be unjust and unreasonable or unduly discriminatory. As a result of the intra-hour scheduling reforms of this Final Rule, the metric against which generator imbalances are measured will be more granular than under current hourly scheduling protocols.

123

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 37.

124

Imbalance charges are calculated by multiplying the quantity of imbalance by a set percentage of incremental or decremental costs defined in three deviation bands. These charges are netted on a monthy basis and settled financially at the end of each month. For example, any deviations greater than ± 7.5 percent (or 10 MW) of the scheduled transaction (applied hourly) will be settled at 125 percent of incremental costs or 75 percent of decremental costs.

See

OATT Schedule 9.

94. The Commission expects 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. For example, we note 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.

125

Based on this experience and the record in this proceeding, the Commission finds that intra-hour scheduling will provide a range of transmission customers with a necessary tool to mitigate exposure to Schedule 9 generator imbalance charges in light of changing conditions.

125

See Entergy Serv. Inc.,

111 FERC ¶ 61,314 (2005).

95. The Commission also finds that, over time, implementation of intra-hour scheduling will allow public utility transmission providers to rely more on planned scheduling and dispatch procedures, and less on reserves, to maintain overall system balance. Under hourly scheduling protocols, the source balancing authority for a transaction is required to honor its transmission schedule across an entire hour, requiring the source balancing authority to have sufficient reserves in place to manage imbalances within the hour, i.e., maintain consistent delivery of the scheduled amount of energy to the sink balancing authority over the hour. This includes reserves to respond to variations in generation output that are moment-to-moment as well as longer-term, but occurring within the hour, represented by the solid line in Figure 1.

ER13JY12.000

96. By moving from hourly to 15-minute scheduling intervals, the amount of imbalance energy for which the source balancing authority is potentially responsible can be reduced, as reflected in Figure 1. This can lead to a corresponding reduction in the amount of capacity held to provide that energy and, in turn, lower reserve-related costs for the source balancing authority, and ultimately consumers. Therefore, the Commission also finds that implementation of intra-hour schedules is necessary in order to ensure that charges for ancillary services through which reserve-related costs are recovered are just and reasonable and not unduly discriminatory.

126

One mechanism that could be used to recover reserve-related costs is generator regulation service. The Commission provides guidance regarding the development of generation regulation charges in section IV.C.2 (Mechanics of Generator Regulation Charge)

infra.

Among other things, public utility transmission providers should consider the extent to which transmission customers are using intra-hour scheduling in evaluating whether to require different transmission customers to provide or otherwise account for different quantities of generator regulation service.

97. For these reasons, the Commission adopts the proposal set forth in the Proposed Rule and directs public utility transmission providers, consistent with the compliance deadlines addressed below, to revise their OATTs to provide an opportunity for transmission customers to submit transmission schedules at 15-minute intervals. In response to Bonneville Power and Xcel, the Commission clarifies that this requirement is intended to allow transmission customers to both modify existing schedules as well as create new schedules, provided that the transmission customer has a transmission reservation in place.

127

The ability to create new transmission schedules within the hour will be particularly important to resources that may seek to provide intra-hour energy products, as discussed further below.

127

To be clear, this Final Rule does not alter the transmission products of the

pro forma

OATT and, therefore, implementation of intra-hour scheduling does not require (yet would not preclude) the intra-hour calculation of ATC or sale of transmission service.

98. The Commission notes that most commenters support the practice of intra-hour scheduling, with disagreement focused primarily on the frequency of schedule adjustments and whether changes to existing scheduling should be paired with other reforms. Balancing the competing considerations raised by commenters, the Commission concludes that a 15-minute scheduling interval is appropriate and declines to impose additional reforms at this time. The Commission appreciates that implementation of other reforms, such as intra-hour imbalance settlement, an intra-hour transmission product, increasing the frequency of resource commitment through sub-hourly dispatch, or the formation of intra-hour imbalance markets, could yield additional benefits for public utility transmission providers and their customers. However, these additional reforms can have significant costs. The Commission's review of the record in this proceeding suggests that a more measured approach is appropriate to take at this time.

128

As noted below, public utility transmission providers will have an opportunity on compliance to demonstrate that alternative intra-hour scheduling proposals are consistent with or superior to the intra-hour scheduling requirements of this Final Rule. Such a proposal could include one or more of the additional reforms requested by commenters, such as the formation of intra-hour imbalance markets.

99. The Commission acknowledges that implementation of intra-hour scheduling can result in a shift of responsibility for holding certain reserves away from the source balancing

authority for export transactions.

129

As explained above, allowing for more granular transmission schedules can reduce the amount of variation in generation output for which the source balancing authority is responsible. The Commission appreciates that, from the sink balancing authority's perspective, scheduling at shorter intervals may result in the purchaser of energy having to manage more frequent changes in scheduled deliveries as compared to scheduling at hourly intervals. As indicated in Figure 2, a purchaser under existing hourly scheduling protocols receives a fixed quantity of energy over the hour from the source balancing authority, whereas use of 15-minute intervals could result in fluctuating deliveries across the hour.

129

E.g.,

Xcel; Iberdrola.

ER13JY12.001

To the extent the purchaser desires to continue receiving a constant delivery of energy across the hour, represented by the dotted line in Figure 2, it may be required to obtain that energy from the market.

130

The Commission concludes that this is an appropriate division of responsibility, as opposed to the current hourly system which places all responsibility for managing variations in generation output across the hour solely on the source balancing authority. Within the hour, the source balancing authority retains its responsibility of providing the energy needed for the VER to meet its schedule, while the purchaser takes on the responsibility of managing more frequent deliveries of scheduled energy.

130

For example, sellers of VER energy could have existing contractual commitments to deliver at constant volumes over specified periods.

100. By shifting responsibility for managing certain variations in generation output to the purchasing entity, purchasing entities will have greater incentive to manage changes in scheduled deliveries from 15-minute interval to 15-minute interval and the portfolio of resources that ultimately manage total VER variability will likely be more cost-effective than under current practices. Specifically, a portfolio of resources that respond over a range of time scales, from very fast to relatively slow, is lower cost than a portfolio that relies on resources designed to manage only the short-run variability of VERs.

131

For instance, portfolio cost savings could result from using a combination of expensive resources with automated generator control and less expensive resources that provide following service rather than using only resources with automated generator control. While the source balancing area could choose to manage VER variability with a portfolio of resources that respond over a range of time, it has little incentive to do so because any additional costs can be recovered from transmission customers. We expect use of a portfolio of resources to lower the overall cost of managing VER variability. The Commission anticipates that buyers and sellers also may respond by developing intra-hour balancing products. EPSA notes that the additional market liquidity created by the ability to schedule transmission intra-hourly can provide opportunities for existing resources to manage system

variability by offering within-hour energy products. This is equally true for market participants seeking to maximize the value of their resources, or lower their purchased power costs, through intra-hour trading. As the liquidity of intra-hour energy products stabilizes, market participants also may begin to commit or otherwise acquire fewer reserves in advance, with the knowledge that they can purchase additional reserves on an as-needed basis from third parties. Requiring public utility transmission providers to offer intra-hour scheduling is a necessary predicate to facilitate these market opportunities.

132

131

See e.g.,

J. Apt,

The Spectrum of Power from Wind Turbines.

Journal of Power Sources, Vol. 169, No. 2, at 369-374 (2007); cited at RenewElec comments at note 4.

132

For example, the Joint Initiative has implemented an electronic platform to facilitate bilateral intra-hour transactions, the Intra-hour Transaction Accelerator Platform (I-TAP), also referred to as the WebExchange.

See http://www.columbiagrid.org/itap-overview.cfm.

101. Notwithstanding broad support in comments for some version of intra-hour scheduling, as noted above, there was significant disagreement in the comments as to the appropriate time interval. Some commenters supported the 15-minute interval proposed by the Commission,

133

while others argued for either shorter (e.g., 5-minute) or longer (e.g., 30-minute) scheduling intervals.

134

In evaluating these comments, the Commission has balanced the competing interests of allowing transmission customers to more closely match schedules with anticipated generation output against not unduly burdening public utility transmission providers in implementing the intra-hour scheduling reform. The Commission concludes that adoption of a 15-minute scheduling interval for purposes of the

pro forma

OATT is reasonable. In its comments on the NOI, NERC states that the ideal scheduling increment would be between 5 and 15 minutes depending on system characteristics.

135

NERC reasoned that, while balancing authorities that schedule energy transactions on an hourly basis may have sufficient regulation resources to maintain the schedule for the hour, reducing scheduling intervals to ten minutes, for example, could make economically dispatchable generators in an adjacent balancing authority available to provide necessary ramping capability through an interconnection.

136

The Commission agrees and, as discussed above, anticipates that the availability of intra-hour scheduling at 15-minute intervals will facilitate the development of ramping products to manage variability in generation output more effectively. For these reasons we adopt 15-minute transmission scheduling as proposed.

133

E.g.,

A123; Alstom Grid; ACSF; Argonne National Lab; BP Companies; CESA; CEERT; Center for Rural Affairs; Clean Line; CGC; Defenders of Wildlife; EPSA; Exelon; First Wind; Independent Energy Producers; NaturEner; Organization of Midwest ISO States; Oregon & New Mexico PUC; Powerex; Public Interest Organizations; SWEA; Tres Amigas; Viridity Energy; Western Grid; Xcel.

134

Compare

Environmental Defense Fund; FriiPower; Independent Power Producers Coalition-West; RenewElec; SEIA; Vestas; and Vote Solar (advocates of shorter) with Bonneville Power; California PUC; CMUA; Montana PSC; NorthWestern; Puget; Snohomish County PUD; Southern California Edison; WUTC (advocates of longer).

135

NERC April 12, 2010 Response to NOI (NERC NOI Comments).

136

NERC NOI Comments.

102. In adopting a 15-minute transmission scheduling interval, we recognize that the cost of moving from hourly to 15-minute transmission scheduling could be substantial. Several transmission providers state that costs will depend heavily on the extent to which intra-hour scheduling is actually used by transmission customers, estimating staffing costs to be in the range of $1-2 million per year if widely used.

137

While these costs are not insignificant, greater use of intra-hour schedules means that more transmission customers are mitigating exposure to Schedule 9 generator imbalance charges and providing greater opportunities for public utility transmission providers to lower reserve-related costs. Commenters generally agree that the cost of implementing intra-hour scheduling will correlate to usage, with lower costs in those systems with fewer intra-hour schedules. In contrast, substantial use of intra-hour scheduling would affirm the usefulness of the option for transmission customers, justifying the added expense of processing a larger number of transmission schedules.

137

E.g.,

Avista; NRECA. To the extent intra-hour scheduling is not widely used by transmission customers, NRECA states its members likely could implement scheduling at 15-minute intervals with software modifications in the range of $50,000 per company, without additional staffing requirements.

103. Many of the costs cited by commenters as being specific to 15-minute scheduling are related to the automation of systems used to process transmission schedules and verify cross-balancing authority aggregate schedules. The Commission notes that it is not mandating automation of scheduling practices, although we expect that each public utility transmission provider will consider whether automation of certain aspects of its system are necessary to implement scheduling at 15-minute intervals. To the extent a public utility transmission provider automates scheduling processes in response to increased scheduling activity, the Commission agrees with NaturEner and Independent Power Producers Coalition-West that automation of these processes represents a secondary benefit of our transmission scheduling reform. Several Commission staff audits have uncovered errors related to manual processing of transmission schedules.

138

These errors resulted in a transmission customer submitting a transmission schedule that resulted in a higher curtailment priority than the underlying transmission service reservation provided, allowed use of firm network service to deliver energy from resources that were not designated resources and allowed use of network transmission service to deliver a sale to a third party. As a result of these errors, the transmission customer may have gained access to transmission service that was not otherwise available, may have inappropriately gained additional protection from curtailment, and avoided payment for point-to-point transmission service. Increased automation of schedule process can reduce such errors and, in turn, ensure that the provision of transmission service is consistent with the

pro forma

OATT.

138

E.g., Puget Sound Energy,

Docket No. PA07-1-000 at 25-27;

MidAmerican Energy Co.,

Audit Report, 112 FERC ¶ 61,346 at PP 30-34 (2005); and

Public Service Company of Colorado,

Docket No. PA05-1-000 at 9-11.

104. Some commenters raising concerns regarding the cost of implementing intra-hour scheduling imply that the proposed scheduling reforms would require changes in settlement procedures for imbalance service or the frequency of resource commitment through sub-hourly dispatch, which they state would require significant investments. For example, EEI and PNW Parties caution that these additional activities would affect computer systems, such as energy management and accounting systems.

139

MidAmerican estimates that upgrading such systems would cost $2.0-2.3 million. Other commenters, however, encourage the Commission to require intra-hour imbalance settlement and sub-hourly dispatch in order to align intra-hour scheduling with financial settlements and resource commitment. The Commission clarifies that the requirements of this Final Rule apply to scheduling practices, not imbalance settlement or sub-hourly dispatch. Public utility transmission providers may continue to calculate

pro forma

Schedule 9 generator imbalance charges on an hourly basis under the

pro forma

OATT and rely on hourly resource commitment practices.

140

139

Eg.,

EEI; PNW Parties.

140

See

Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 722; Order No. 890-A, FERC Stats. & Regs. ¶ 61,297 at P 325 & n.117.

105. Notwithstanding the continued ability of public utility transmission providers to rely on hourly calculation of Schedule 9 generator imbalances, as a result of the intra-hour scheduling reforms of this Final Rule, the metric against which generator imbalances are measured will be more granular than under current hourly scheduling protocols. To the extent a public utility transmission provider believes that aligning the imbalance settlement with the intra-hour scheduling interval or implementing sub-hourly dispatch will result in more efficient operations, provide appropriate price signals to customers, or address other potential issues, it may seek any authorizations necessary from the Commission to do so under section 205 of the FPA.

141

Such proposals could be submitted contemporaneously with the compliance filing in response to this Final Rule or at such other time the public utility transmission provider believes appropriate.

141

For example, PNW Parties and Idaho Power note that the financial incentives some transmission customers have to maximize output over an hour may in some instances counteract financial incentives to adjust transmission schedules on a 15-minute basis.

106. Several commenters request that the Commission allow for regional variation in scheduling protocols.

142

In the Western Interconnection, many public utility transmission providers already have implemented some form of intra-hour scheduling at 30-minute intervals as part of an effort to enhance the operation of bilateral markets in the Western Interconnection.

143

Other tools recently implemented in the West include the I-TAP electronic platform to schedule energy and request transmission, the Dynamic Scheduling System to facilitate dynamic scheduling,

144

and the ACE Diversity Interchange Program to allow netting of momentary imbalances across participating balancing authority footprints.

145

Public utility transmission providers, state regulators, and others in the West are studying the impact of these recent initiatives, as well as the potential benefits and costs of pursuing additional market enhancements in the future, such as formation of an energy imbalance market. The Commission acknowledges that future market enhancements in addition to existing 30-minute scheduling practices and the above-referenced tools, might yield equivalent or greater benefits to transmission customers and public utility transmission providers when compared to reducing the scheduling interval from 30 to 15 minutes and therefore could be consistent with or superior to the Final Rule's intra-hour scheduling requirements.

142

E.g.,

Avista; Bonneville Power; California ISO; CESA; CMUA; California PUC; Detroit Edison; EEI; FirstEnergy; Grant PUD; Idaho Power; Independent Power Producers Coalition-West; ISO/RTO Council; Midwest ISO; National Grid; Northwestern; NRECA; New York ISO; NV Energy; Pacific Gas & Electric; PJM; PNW Parties; Public Power Council; Puget; SMUD; Tacoma Power; WUTC; and WestConnect.

143

See e.g.,

Arizona Public Service Co.,

137 FERC ¶ 61,023 (2011),

NorthWestern Corp.,

136 FERC ¶ 61,119 (2011).

144

See

Joint Initiative.

145

See

NERC,

DRAFT Reliability Guideline: ACE Diversity Interchange

(June 2012),

available at http://www.nerc.com/docs/oc/rs/Draft%20ADI%20Reliability%20Guideline%20-%20V1%20060112.pdf.

107. The Commission therefore affirms the ability of public utility transmission providers to submit alternative proposals that are consistent with or superior to the intra-hour scheduling requirements of this Final Rule and are otherwise just and reasonable and not unduly discriminatory or preferential.

146

To make such a showing, a public utility transmission provider must demonstrate in its compliance filing 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, when compared to implementation of the intra-hour scheduling requirements of this Final Rule under market practices currently in place within the region, including tools referenced above that already have been implemented in the West.

147

The public utility transmission provider must include in its compliance filing the tariff provisions necessary to implement its proposal, including the interval at which transmission customers may submit transmission schedules. The public utility transmission provider also must address how its proposed scheduling interval is consistent with other scheduling practices within its region. Finally, in recognition that implementation of intra-hour scheduling can result in a shift of responsibility for holding certain reserves away from the source balancing authority for export transactions, public utility transmission providers may consider the extent to which alternative proposals result in savings to transmission customers across multiple public utility transmission provider systems when making the demonstration required above.

146

Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,770 (permitting public utility transmission providers to propose tariff modifications that are consistent with or superior to the requirements of the

pro forma

OATT).

147

To the extent such an alternative proposal includes a commitment to develop and implement additional market enhancements in the future, the public utility transmission provider must provide in its compliance filing: A commitment by senior management to develop and implement the proposal; a description of collaborative efforts to date and timeline for future efforts in support of developing the proposal; and, the date by which the proposed market enhancement will be implemented.

108. Turning to other issues raised by commenters, the Commission is not convinced by arguments that the current exemption from third-tier generator imbalance penalties for intermittent resources should be eliminated to create an incentive for VERs to take advantage of the option to update transmission schedules every 15 minutes.

148

In Order No. 890, the Commission found intermittent generators cannot always accurately follow their schedules and that high penalties will not lessen the incentive to deviate from their schedules.

149

While the implementation of 15-minute scheduling provides an opportunity for VERs to better align transmission schedules with actual generation, the Commission continues to believe that third-tier generator imbalance penalties are unduly punitive for VERs given their relative inability to accurately follow schedules whether submitted on an hourly or 15-minute interval. The Commission concludes that the ability to avoid penalties in the first two tiers of generator imbalance charges will provide a sufficient incentive for VERs to adjust transmission schedules, to the extent they believe such adjustments will mitigate exposure to Schedule 9 generator imbalance charges. If a public utility transmission provider believes it necessary to address intentional deviations, it may propose revisions to Schedule 9 generator imbalance service pursuant to section 205 of the FPA.

150

Such proposals would need to demonstrate that VERs are not adjusting their transmission schedules despite their reasonable ability to foresee that

output will deviate significantly from existing transmission schedules.

151

148

E.g.,

Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.

149

Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 665.

150

Cf. id.

P 676 (noting the ability of public utility transmission providers to propose additional imbalance penalties for intentional deviations). Alternatively, the public utility transmission provider may propose alternative designs for other ancillary services rates to, for example, offer lower rates to those transmission customers committing to use intra-hour scheduling.

151

The Commission notes that there is a relationship between a public utility transmission provider's potential need for alternative imbalance charge structures and the period used for imbalance settlements. Reinstating third-tier imbalance penalties in combination with shortened imbalance settlements would more likely punish VERs for variability that they cannot control, contrary to the exemption granted in Order No. 890 and affirmed here.

109. The Commission acknowledges comments made by some, particularly in the Pacific Northwest, asserting that the benefits of intra-hour scheduling will not be fully realized if non-jurisdictional entities do not adopt a consistent scheduling interval.

152

However, the Commission does not believe that limitations in our ratemaking jurisdiction over non-public utilities should stop us from moving ahead with reforms applicable to public utilities simply because the impact of those reforms might be more significant with participation by all entities. As explained above, requiring all public utility transmission providers to offer 15-minute transmission scheduling will enable public utility transmission providers and their customers to manage system variability more effectively. Therefore, the Commission is hopeful that non-jurisdictional transmission providers will voluntarily choose to implement 15-minute transmission scheduling in order to better manage variations in generation output. We understand that the existence of compatible business practices within a region is beneficial, and we encourage both jurisdictional and non-jurisdictional transmission providers to continue to coordinate and collaborate in order to maintain the continuity of the system and address issues as they arise. This includes collaboration in the development of any alternative compliance proposals developed by public utility transmission providers.

152

E.g.,

Avista; California ISO; Duke; Idaho Power; NorthWestern; NV Energy; PNW Parties; Puget; Southern California Edison; Southern; Tres Amigas.

110. The Commission disagrees with comments by Southern and others that different scheduling intervals between jurisdictional and non-jurisdictional transmission providers may negatively affect reliability within an interconnection.

153

In the event a non-jurisdictional transmission provider only accepts hourly schedules, any attempt to submit an intra-hour schedule for delivery to the non-jurisdictional transmission provider would be rejected, as several commenters note.

154

This may lead to an inability to implement 15-minute scheduling fully and, in turn, could result in less effective management of system variability. However, the Commission does not believe that it would create any reliability challenges beyond those that exist today under hourly scheduling protocols. The Commission notes that voluntary efforts to implement intra-hour scheduling on 30-minute intervals in the Western Interconnection referenced above have not been uniformly applied, yet do not appear to have negatively affected reliability.

153

E.g.,

EEI; Idaho Power; NorthWestern; Southern; Tacoma Power.

154

E.g.,

PNW Parties; Puget; WUTC.

111. In response to concerns raised by Snohomish County PUD and Grays Harbor PUD regarding “slice” contracts with Bonneville Power, the Commission acknowledges that some existing power supply arrangements may not be flexible enough to take advantage of the benefits of intra-hour scheduling. Over time, the Commission anticipates that the market will respond to the availability of intra-hour scheduling through the development of new balancing products as well as modifications of existing arrangements where appropriate. However, in the case where the terms of an existing contract are inconsistent with intra-hour scheduling and cannot be modified, the Commission appreciates that the benefits of intra-hour scheduling may not be available with respect to that particular transaction.

112. In response to comments by WestConnect and NorthWestern that a 15-minute scheduling interval is inconsistent with the standard 20-minute generator ramp rate used in the West, we note that many of the Joint Initiative transmission providers—including members from WestConnect—have already implemented a 10-minute ramp rate to accommodate 30-minute transmission schedules. To the extent changes in ramping are necessary to support use of a 15-minute transmission schedules, it does not appear that such changes present a significant impediment for public utility transmission providers.

113. A number of commenters question the applicability of the intra-hour scheduling requirements to public utility transmission providers in RTO and ISO regions.

155

The Commission clarifies that the implementation of 15-minute transmission scheduling will only apply to intertie transactions in organized wholesale energy markets. The Commission finds that a consistent scheduling interval for transactions among all public utility transmission providers, including RTOs, is necessary in order to attain the benefits of intra-hour scheduling noted above. Additional reforms to other markets requested by commenters, such as adjustments to day-ahead markets, are beyond the scope of this rulemaking.

155

E.g.,

AWEA; Iberdrola; ISO New England; Massachusetts DPU; PJM; Public Interest Organizations; RENEW; Sunflower and Mid-Kansas; Western Farmers.

2. Implementation of Intra-Hour Scheduling

114. Commenters raise a number of additional issues related to how the intra-hour scheduling requirements adopted in this Final Rule should be implemented. The Commission addresses these issues below, including the following: (1) The appropriate notification period for submitting transmission schedules; (2) the recovery of costs associated with implementing intra-hour scheduling; (3) clarifications regarding the definition of transmission schedule, curtailment priorities, and calculations of ATC; (4) review of NERC reliability standards and NAESB business practices; and (5) other issues related to high voltage direct current (HVDC) transmission lines, dynamic scheduling, and the geographic location of resources used to provide reserves.

a. Notification Time for Submission of Transmission Schedule

i. Commission Proposal

115. In the Proposed Rule, the Commission proposed to allow all transmission customers the option of submitting intra-hour schedules up to 15 minutes before each scheduling interval.

156

Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 41.

ii. Comments

116. Several commenters ask the Commission to retain the existing 20-minute notification time for submission of transmission schedules, arguing that schedules should be submitted no later than 20 minutes prior to the start of the schedule as required by NERC Reliability Standards INT-005, INT-006, INT-008, and NAESB WEQ-004 Appendix D.

157

Commenters contend that allowing only 15 minutes between schedule submission and start would not provide enough time for transmission operators to adequately evaluate, approve, and implement transmission schedules. ISO/RTO Council adds that changing to a 15-minute notice period will require

transmission operators to change their current systems and increase staff levels for processing transmission schedule requests. PJM comments that the 20-minute notification deadline is an established industry standard and that it should not be changed to 15 minutes.

157

E.g.,

Duke; EEI; Entergy; NRECA; PJM; Puget; Southern.

117. Although not opposed to the Commission's proposal, NaturEner states that a shorter notification period would result in abbreviated response times for everyone in the scheduling process, including transmission customers. NaturEner asks the Commission to clarify that transmission providers have the discretion to accept schedule changes after the notification deadline. NaturEner contends that inclusion of such a clarification both supports the reform's underlying rationales and avoids any unnecessary future confusion regarding whether a balancing authority or transmission provider possesses such discretion.

iii. Commission Determination

118. The Commission will retain the existing 20-minute prior notification period for the submission of a transmission schedule and not adopt its proposal. The Commission agrees with commenters that the existing 20-minute prior notification period is needed to adequately evaluate, approve and implement transmission schedules. Accordingly, the Commission retains the existing notific

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