139 FERC ¶ 61,246

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

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

Integration of Variable Energy Resources

(Issued June 22, 2012)

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: (1) offer intra-hourly transmission 

scheduling; and, (2) 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. 

EFFECTIVE DATE: This rule will become effective [insert date 60 days after 

publication in the FEDERAL REGISTER].
Docket No. RM10-11-000 - 2 -

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

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Jon Wellinghoff, Chairman;

 Philip D. Moeller, John R. Norris,

 Cheryl A. LaFleur, and Tony T. Clark.

Integration of Variable Energy Resources Docket No. RM10-11-000

ORDER NO. 764

FINAL RULE

(Issued June 22, 2012)

TABLE OF CONTENTS

I. Introduction ............................................................................................................................1.

Background ............................................................................................................................6.

II. The Need for Reform ...........................................................................................................11.

A. Commission Proposal.......................................................................................................11.

B. Comments.........................................................................................................................12.

C. Commission Determination .............................................................................................16.

III. Legal Authority to Implement Proposed Reforms .............................................................25.

A. Commission Proposal.......................................................................................................25.

B. Comments ........................................................................................................................26.

C. Commission Determination..............................................................................................36.

IV. Proposed Reforms ...............................................................................................................51.

A. Intra-hour Scheduling ......................................................................................................51.

1. Intra-Hour Scheduling Requirement ............................................................................52.

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.
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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.
Docket No. RM10-11-000 - 3 -

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)1 and ensure that the rates, terms, and conditions for Commissionjurisdictional services provided by public utility transmission providers are just and 

reasonable and not unduly discriminatory or preferential.2

 As the Commission noted in 

the Proposed Rule, VERs are making up an increasing percentage of new generating 

capacity being brought on-line.3

 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 

 1 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). 

2 16 U.S.C. 824e (2006).

3 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 13. 
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and that public utility transmission providers have the information needed to efficiently 

manage reserve-related costs. 

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 
Docket No. RM10-11-000 - 5 -

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 
Docket No. RM10-11-000 - 6 -

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.4

 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, nondiscriminatory transmission tariff that contains minimum terms and conditions of nondiscriminatory service. As relevant here, the pro forma OATT contains terms for 

scheduling transmission service and the provision of ancillary services. 

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 

 4 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 

v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002). 
Docket No. RM10-11-000 - 7 -

concluded that there was a pressing need for a single set of procedures and a single, 

uniformly applicable interconnection agreement for large generator interconnections.5

 

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.6

 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.7

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.8

 Therefore, Commission exempted wind resources from 

certain sections of the LGIA and added Appendix G to the LGIA, as a placeholder for the 

 5 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 v. FERC, 

475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008). 

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

7 Id.

8 Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160 at P 407 & n.85.
Docket No. RM10-11-000 - 8 -

inclusion of interconnection standards specific to newer technologies.9

 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.10

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.11 Among other things, the Commission adopted a set of 

transmission planning principles,12 created a new pro forma ancillary service schedule 

designed to address generator imbalances,13 and instituted a new conditional firm 

 9 Id.

10 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).

11 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).

12 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).

13 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at PP 663-72.
Docket No. RM10-11-000 - 9 -

transmission product.14 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.15 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.16 

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.17 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.18 In order to determine whether any 

rules, regulations, tariffs or industry practices within the Commission’s jurisdiction 

 14 Id. PP 911-15.

15 Id. P 72.

16 Id. P 665.

17 Integration of Variable Energy Resources Notice of Inquiry, FERC Stats. & 

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

18 Id. P 2.
Docket No. RM10-11-000 - 10 -

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.19 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.

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 

 19 Id. P 12.
Docket No. RM10-11-000 - 11 -

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 costeffective manner, consistent with open access principles.20 

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.21 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 

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

21 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. 
Docket No. RM10-11-000 - 12 -

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. 

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 
Docket No. RM10-11-000 - 13 -

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 
Docket No. RM10-11-000 - 14 -

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.22 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.23 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.24 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 

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

23 Id. P 19.

24 Id. PP 23-24.
Docket No. RM10-11-000 - 15 -

that further study is required for many of the remaining issues raised in the Notice of 

Inquiry.25 

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.26 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 reserverelated costs recovered from transmission customers through other ancillary services 

charges. 

 25 Id. PP 12, 24.

26 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. 
Docket No. RM10-11-000 - 16 -

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-

2010.27 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.28 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 2035.29 This recent and future growth is being facilitated by 

 27 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. 

28 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-MarketReport_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/SMIYIR-2011-ES.pdf. 

29 Annual Energy Outlook at 75, available at 

http://www.eia.gov/forecasts/archive/aeo11/pdf/0383(2011).pdf. 
Docket No. RM10-11-000 - 17 -

developments in state and federal public policies that encourage the expansion of VER 

generation.30

20. As NERC has noted, higher levels of variable generation can alter the operation 

and characteristics of the bulk power system.31 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.32 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 

 30 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/othrmkts/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. No. 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.

31 NERC, Accommodating High Levels of Variable Generation at 8, available at

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

32 Id. at 59. 
Docket No. RM10-11-000 - 18 -

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. 

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.33 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. 

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 

 33 Order No. 1000, 76 FR 49842, FERC Stats. & Regs. ¶ 31,323 at PP 45-46.
Docket No. RM10-11-000 - 19 -

resources.34 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.

 34 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.
Docket No. RM10-11-000 - 20 -

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 
Docket No. RM10-11-000 - 21 -

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.35 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.

 35 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.
Docket No. RM10-11-000 - 22 -

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.36 The 

Commission preliminarily concluded that the proposed rules are necessary to ensure that 

 36 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.
Docket No. RM10-11-000 - 23 -

rates for Commission-jurisdictional services are just and reasonable and to remedy undue 

discrimination in existing transmission system operations.37 

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.38 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.”39 EEI and 

Southern maintain that these types of decisions should be left to public utility 

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

38 EEI and Southern argue, for example, that the Commission must rely upon 

factual, record findings to support these proposed mandates. EEI (citing National Fuels 

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

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

39 EEI (citing Atlantic City v. FERC, 295 F.3d 1,21 (D.C. Cir. 2002) (quoting 

United Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 350 U.S. 332341 (1956) and City of 

Winnfield v. FERC, 744 F.2d 871, 876 (D.C. Cir. 1984)); Southern (citing Atlantic City v. 

FERC, 295 F.3d 1,21 (D.C. Cir. 2002) (quoting United Gas Pipe Line Co. v. Mobile Gas 

Serv. Corp, 350 U.S. 332341 (1956) and City of Winnfield v. FERC, 744 F.2d 871, 876 

(D.C. Cir. 1984)).
Docket No. RM10-11-000 - 24 -

transmission providers and RTOs and should be informed by regional conditions and not 

dictated on a generic basis.

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.40 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 D.C. 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 

 40 E.g., Southern; EEI.
Docket No. RM10-11-000 - 25 -

of the effects or impacts of those requirements on different customer groups.41 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. 

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 

 41 Southern (citing Enron Power Marketing, Inc. v. FERC, 296 F.3d 1148 (D.C. 

Cir. 2002) (Enron)); EEI (citing Enron, 296 F.3d 1148).
Docket No. RM10-11-000 - 26 -

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.42 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.43 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. 

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 

 42 Southern (citing Ala Elec. Coop. v. 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 scheduling and imbalance purposes. Id. (citing City of Vernon v. FERC,

845 F.2d 1042, 1045-46 (D.C. Cir. 1988)). 
Docket No. RM10-11-000 - 27 -

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.44 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. 

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 

 44 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). 
Docket No. RM10-11-000 - 28 -

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.”45 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.

 45 Southern (citing Cal. Indep. Sys. Operator Co. v. FERC, 372 F.3d 395, 398 

(D.C. Cir. 2004) (citing Atlantic City Elec. Co. v. FERC, 295 F.3d at 8)).
Docket No. RM10-11-000 - 29 -

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.46 

When applied in a rulemaking context, “the substantial evidence test is identical to the 

familiar arbitrary and capricious standard.”47 The Commission thus must show that a 

“reasonable mind might accept” that the evidentiary record here is “adequate to support a 

conclusion,”48 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.

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 

 46 16 U.S.C. 825l(b). 

47 Wisc. Gas Co. v. FERC, 770 F.2d 1144, 1156 (1985); see also Associated Gas 

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

48 Dickenson v. Zurko, 527 U.S. 150, 155 (1999). 
Docket No. RM10-11-000 - 30 -

all generation resources were similarly situated.49 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. 

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 

 49 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).
Docket No. RM10-11-000 - 31 -

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.50 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.51 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.52

 50 National Fuel, 468 F.3d at 840.

51 Id. at 841. 

52 Id. at 844.
Docket No. RM10-11-000 - 32 -

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.53 

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. 

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 

 53 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.
Docket No. RM10-11-000 - 33 -

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.

54 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.

55

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 

 54 Enron, 296 F.3d at 1151. 

55 Id. at 1153-54.
Docket No. RM10-11-000 - 34 -

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.56 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.57 

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 

 56 Id. at 1151-52.

57 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. 
Docket No. RM10-11-000 - 35 -

in how different customers will use or benefit from those tariff provisions.58 However, 

nothing in Enron mandates that result.

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.59 In 

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.60

 58 Id.

59 Southern (citing Alabama Power, 684 F.2d at 29); EEI (citing Alabama Power,

684 F.2d 20).

60 Alabama Power, 684 F.2d at 28-29.
Docket No. RM10-11-000 - 36 -

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.61 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.62 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.

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

62 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 v. 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 v. 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. v. 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.”).
Docket No. RM10-11-000 - 37 -

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.63

 63 See Transmission Access Policy Study Group v. 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. v. 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. v. 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).
Docket No. RM10-11-000 - 38 -

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.64 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.65 We again recognize that VERs, by 

definition,66 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.67 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 

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

65 Id. P 663 (requiring that generator imbalance provisions account for the special 

circumstances presented by intermittent generators).

66 See supra note 1 (defining VER).

67 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.”).
Docket No. RM10-11-000 - 39 -

giving public utility transmission providers a better understanding of expected energy 

flows on their systems. 

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.68 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.69 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 

 68 TAPS, 225 F.3d at 688 (citing Wisc. Gas Co. v. FERC, 770 F.2d at 1158).

69 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.
Docket No. RM10-11-000 - 40 -

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.70 

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.71 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.

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 

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

71 See infra § IV.B.1 (Data Requirements).
Docket No. RM10-11-000 - 41 -

rates subject to the Commission’s jurisdiction under the FPA.72 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.73 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. 

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 

 72 See Cal. Indep. Sys. Oper. v. FERC, 372 F.3d 395 (D.C. Cir. 2004).

73 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at 12.
Docket No. RM10-11-000 - 42 -

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 
Docket No. RM10-11-000 - 43 -

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.74

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.75

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

75 Id. PP 42-43.
Docket No. RM10-11-000 - 44 -

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,76 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. 

 76 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.
Docket No. RM10-11-000 - 45 -

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.77 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. 

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. 

 77 E.g., CEERT; Powerex; Public Interest Organizations; Vestas.
Docket No. RM10-11-000 - 46 -

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.78 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. 

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 

 78 E.g., Argonne National Lab; Environmental Defense Fund; Public Interest 

Organizations.
Docket No. RM10-11-000 - 47 -

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.79 

59. However, other commenters oppose mandatory intra-hour scheduling, arguing 

generally that current scheduling practices are neither preferential nor unduly 

discriminatory.80 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 

 79 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.

80 E.g., ELCON; Midwest ISO; NV Energy; Southern. 
Docket No. RM10-11-000 - 48 -

are better understood.81 LADWP submits that intra-hour scheduling should not be 

implemented until it has been fully vetted and researched to assess operational 

capabilities and coordination.

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 intrahour scheduling.82 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 

 81 E.g., California PUC; LADWP; NorthWestern; NV Energy; Pacific Gas & 

Electric.

82 E.g.E.g., Avista; Bonneville Power; M-S-R Public Power Agency; Xcel.
Docket No. RM10-11-000 - 49 -

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. 

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.83 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 

 83 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.
Docket No. RM10-11-000 - 50 -

charges through more accurate schedules.84 EPSA notes that the proposed 15-minute 

scheduling interval is consistent with NERC recommendations for achieving greater 

flexibility while meeting relevant reliability requirements.85 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. 

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. 

 84 E.g., BP Energy; CEERT; CGC; Defenders of Wildlife; Duke; NextEra; Public 

Interest Organizations; SEIA; Vestas; Xcel. 

85 EPSA (citing NERC April 12, 2010 Response to NOI at 17-18).
Docket No. RM10-11-000 - 51 -

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

is too long.86 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.87 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.

 86 E.g., Environmental Defense Fund; FriiPower; Independent Power Producers 

Coalition-West; RenewElec; SEIA; Vestas.

87 E.g., Environmental Defense Fund; Independent Power Producers CoalitionWest; RenewElec.
Docket No. RM10-11-000 - 52 -

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

short.88 Several commenters recommend an initial 30-minute intra-hour scheduling 

interval to coincide with current regional initiatives or as a general first step.89 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.90 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.

 88 E.g., LADWP; Montana PSC; NV Energy; Puget.

89 E.g., Bonneville Power; California ISO; California PUC; CMUA; Montana 

PSC; NorthWestern; NV Energy; Snohomish County PUD; Southern California Edison; 

WUTC.

90 E.g., Bonneville Power; California PUC; CMUA; FirstEnergy; NorthWestern; 

Snohomish County PUD; Southern California Edison.
Docket No. RM10-11-000 - 53 -

65. Some commenters contend that a 15-minute scheduling interval does not support 

the standard 20-minute generator/scheduling ramp rate in the West.91 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. 

66. Bonneville Power and Xcel request clarification that “intra-hour scheduling 

adjustments” include both adjustments to existing schedules and the submission of new 

schedules.92 MidAmerican requests clarification as to whether intra-hour scheduling is 

intended to be available only within the current hour or also in future hours.

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 

 91 E.g., LADWP; NorthWestern; PNW Parties; Tacoma Power; WestConnect.

92 Bonneville Power; Xcel.
Docket No. RM10-11-000 - 54 -

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.93 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.

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 

 93 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.
Docket No. RM10-11-000 - 55 -

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.94 Several of these commenters note that there are regional efforts 

and pilot programs underway that are aimed at efficiently managing the integration of 

 94 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.
Docket No. RM10-11-000 - 56 -

VERs and providing an opportunity for intra-hour scheduling.95 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,96 the WECC Efficient Dispatch Toolkit,97 and a pilot between Bonneville 

Power and the California ISO to evaluate the use of intra-hour scheduling on the 

California-Oregon Intertie.98 Several commenters suggest that the Commission should 

 95 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.

96 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. 

97 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. 

98 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. 
Docket No. RM10-11-000 - 57 -

conduct technical conferences to investigate the relative merits of these and alternative 

approaches prior to imposing a uniform national mandate.99

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.

 99 E.g., California ISO; Grays Harbor PUD; Pacific Gas & Electric; SMUD; 

Snohomish County PUD.

100 E.g., Avista; Bonneville Power; California PUC; EEI; Idaho Power; National 

Grid; NorthWestern; NRECA; NV Energy; PNW Parties.

101 Grant PUD at 4.
Docket No. RM10-11-000 - 58 -

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 intrahour.

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 

 102 E.g., ISO/RTO Council; NorthWestern; Pacific Gas & Electric; PNW Parties; 

Public Power Council; Puget.

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. 
Docket No. RM10-11-000 - 59 -

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. 

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 

 104 E.g., AWEA; Iberdrola; Public Interest Organizations; and RENEW.
Docket No. RM10-11-000 - 60 -

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. 

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 

 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.
Docket No. RM10-11-000 - 61 -

recommends that the Commission place responsibility on the balancing authority to 

approve intra-hour scheduling changes made in accordance with an approved tariff. 

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. 

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 

 107 E.g., Avista; California ISO; Duke; EEI; Idaho Power; NorthWestern; NV 

Energy; PNW Parties; Puget; Southern California Edison; Southern; Tres Amigas; 

WUTC. 
Docket No. RM10-11-000 - 62 -

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 
Docket No. RM10-11-000 - 63 -

development and ongoing administrative costs, such as modifying Open Access SameTime 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 

 108 E.g., Avista; Bonneville Power; EEI; Grant PUD; MidAmerican; NRECA; 

NorthWestern; PNW Parties; Puget; Snohomish PUD; Southern California Edison; 

Southwestern; Tacoma Power; TVA.
Docket No. RM10-11-000 - 64 -

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. 

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 

 109 E.g., Avista; Bonneville Power; Grant PUD; MidAmerican; NorthWestern; 

PNW Parties; Puget; Snohomish County PUD; Southwestern; Tacoma Power; TVA.
Docket No. RM10-11-000 - 65 -

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. 

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 intrahour 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 

 110 Avista at 12, 14 (emphasis in original).

111 MidAmerican at 14.
Docket No. RM10-11-000 - 66 -

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.
Docket No. RM10-11-000 - 67 -

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. 

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 

 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). 
Docket No. RM10-11-000 - 68 -

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 intrahour schedules from VERs that continue to schedule on an hourly basis.

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. 

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 

 114 E.g., Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.

115 E.g., Avista; AWEA; RenewElec; Vote Solar.

116 E.g., EEI; Duke; Idaho Power; Southern.
Docket No. RM10-11-000 - 69 -

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. 

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. 

 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)). 

118 E.g., AWEA; CEERT; Invenergy Wind.
Docket No. RM10-11-000 - 70 -

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. 

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.
Docket No. RM10-11-000 - 71 -

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 dayahead 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. 

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 

 119 E.g., American Clean Skies; Invenergy Wind.
Docket No. RM10-11-000 - 72 -

which reserve-related costs are recovered are just and reasonable and are not unduly 

discriminatory.120

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.

 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.

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

122 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 665.
Docket No. RM10-11-000 - 73 -

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.
Docket No. RM10-11-000 - 74 -

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 forcedoutage 

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.

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 

 125 See Entergy Serv. Inc., 111 FERC ¶ 61,314 (2005).
Docket No. RM10-11-000 - 75 -

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. 

Figure 1

Hourly Schedule vs Intra-Hour Schedule at Source BA

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

1 16 31 46 61 76 91 106

Time (mins)

MW

Hourly Schedule Intra-Hour Schedule VER Actual Output

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 
Docket No. RM10-11-000 - 76 -

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

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. 

 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.

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. 
Docket No. RM10-11-000 - 77 -

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 

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 

 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.

129 E.g., Xcel; Iberdrola.
Docket No. RM10-11-000 - 78 -

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. 

Figure 2

Hourly Schedule vs Intra-Hour Schedule at Sink BA

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

170

1 16 31 46 61 76 91 106

Time (mins)

MW

Hourly Schedule Intra-Hour Schedule Load

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 
Docket No. RM10-11-000 - 79 -

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.

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 serice rather than using only resources with automated generator control. 

 130 For example, sellers of VER energy could have existing contractual 

commitments to deliver at constant volumes over specified periods.

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.
Docket No. RM10-11-000 - 80 -

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 intrahour 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 intrahour 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 

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 

 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/itapoverview.cfm. 
Docket No. RM10-11-000 - 81 -

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 

 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).
Docket No. RM10-11-000 - 82 -

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. 

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 reserverelated costs. Commenters generally agree that the cost of implementing intra-hour 

scheduling will correlate to usage, with lower costs in those systems with fewer intrahour schedules. In contrast, substantial use of intra-hour scheduling would affirm the 

 136 NERC NOI Comments.

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. 
Docket No. RM10-11-000 - 83 -

usefulness of the option for transmission customers, justifying the added expense of 

processing a larger number of transmission schedules. 

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 

 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.
Docket No. RM10-11-000 - 84 -

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. 

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

 139 Eg., EEI; PNW Parties.
Docket No. RM10-11-000 - 85 -

Schedule 9 generator imbalance charges on an hourly basis under the pro forma OATT

and rely on hourly resource commitment practices.140 

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 intrahour 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.

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

scheduling protocols.142 In the Western Interconnection, many public utility transmission 

 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.

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. 

142 E.g., Avista; Bonneville Power; California ISO; CESA; CMUA; California 

PUC; Detroit Edison; EEI; FirstEnergy; Grant PUD; Idaho Power; Independent Power 

 

(continued...)
Docket No. RM10-11-000 - 86 -

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 abovereferenced tools, might yield equivalent or greater benefits to transmission customers and 

public utility transmission providers when compared to reducing the scheduling interval 

 

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.
Docket No. RM10-11-000 - 87 -

from 30 to 15 minutes and therefore could be consistent with or superior to the Final 

Rule’s intra-hour scheduling requirements.

107. The Commission therefore affirms the ability of public utility transmission 

providers to submit alternative proposals that are consistent with or superior to the intrahour 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 

 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.
Docket No. RM10-11-000 - 88 -

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.

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 

 148 E.g., Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC. 

149 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 665.
Docket No. RM10-11-000 - 89 -

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 

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 

 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. 

152 E.g., Avista; California ISO; Duke; Idaho Power; NorthWestern; NV Energy; 

PNW Parties; Puget; Southern California Edison; Southern; Tres Amigas. 
Docket No. RM10-11-000 - 90 -

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.

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 nonjurisdictional transmission provider only accepts hourly schedules, any attempt to submit 

an intra-hour schedule for delivery to the non-jurisdictional transmission provider would 

 153 E.g., EEI; Idaho Power; NorthWestern; Southern; Tacoma Power.
Docket No. RM10-11-000 - 91 -

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. 

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 

 154 E.g., PNW Parties; Puget; WUTC.
Docket No. RM10-11-000 - 92 -

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.

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 

 155 E.g., AWEA; Iberdrola; ISO New England; Massachusetts DPU; PJM; Public 

Interest Organizations; RENEW; Sunflower and Mid-Kansas; Western Farmers.
Docket No. RM10-11-000 - 93 -

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

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 

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

157 E.g., Duke; EEI; Entergy; NRECA; PJM; Puget; Southern.
Docket No. RM10-11-000 - 94 -

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. 

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 notification period set forth in sections 13.8 and 14.6 of 

the pro forma OATT, which permits scheduling changes up to 20 minutes (or a 

reasonable time that is generally accepted in the region and is consistent and adhered to 

by the transmission provider) before the start of the next schedule change provided that 

the delivering party and receiving party also agree to the schedule modification. In 
Docket No. RM10-11-000 - 95 -

response to NaturEner, the existing language of the pro forma OATT provides adequate 

flexibility for transmission providers to adopt alternative deadlines for accepting 

scheduling changes. 

b. Recovery of Intra-Hour Scheduling Costs

i. Commission Proposal

119. In the Proposed Rule, the Commission proposed to allow public utility 

transmission providers to recover any costs incurred to implement the proposed intrahour scheduling reform pursuant to Schedule 1 of a transmission provider’s OATT.158

ii. Comments

120. Several commenters support the Commission’s proposal, arguing that the benefits 

of intra-hour scheduling apply to more than VERs and, thus, costs relating to the 

implementation of intra-hour scheduling should be allocated to all transmission 

customers under Schedule 1 of the pro forma OATT.159 For example, NextEra contends 

that intra-hour scheduling would provide long-term benefits for all customers through 

savings on reserve procurement. Public Interest Organizations agree, arguing that the 

initial costs of establishing 15-minute scheduling are an upfront investment that will yield 

exponential returns over time in the form of direct economic savings from increased grid 

efficiency and reliability, as well as energy security, greenhouse gas and other pollutant 

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

159 E.g., Environmental Defense Fund; NextEra; Public Interest Organizations.
Docket No. RM10-11-000 - 96 -

reductions, and job creation that accompanies increased renewable VER penetration. 

Center for Rural Affairs supports recovery of intra-hour scheduling costs to all 

beneficiaries through Schedule 1 in order to mitigate any challenge that this reform may 

present for small transmission providers, especially in rural communities with smaller 

areas of distribution. NaturEner points to the Joint Initiative as an example of allocating 

the hardware and software costs associated with implementation of intra-hour scheduling 

to all participants using the intra-hour scheduling system, i.e., the balancing authorities, 

transmission providers, and transmission customers. While Organization of Midwest ISO 

States supports the proposal, it asks that a clear showing of the costs incurred to 

implement intra-hour scheduling be required prior to allowing for recovery of those costs.

121. Other commenters disagree with the Commission’s proposal to allow the costs 

associated with implementing intra-hour scheduling to be recovered through Schedule 1 

and, instead, contend that such costs should be allocated to VERs and their customers.160 

These commenters argue that intra-hour scheduling will be predominantly used by and 

benefit VERs and their customers.161 ELCON contends that traditional generation 

resources do not require intra-hour scheduling. In the Pacific Northwest, WUTC claims 

that intra-hour scheduling would be utilized almost exclusively by wind and other VERs, 

 160 E.g., Avista; ELCON; Grant PUD; Montana PSC; Natural Gas; NorthWestern; 

NRECA; Puget; WUTC.

161 E.g., Avista; ELCON; Grant PUD; MidAmerican; NorthWestern; NRECA; 

Puget; WUTC.
Docket No. RM10-11-000 - 97 -

and not by thermal or hydropower resources. WUTC agrees that assignment of costs to 

those who cause them is essential to fair and just rates and to economic efficiency. Puget 

agrees that the only parties to benefit from 15-minute scheduling are VERs that are 

potentially able to reduce Schedule 9 generator imbalance charges by adjusting their 

schedules within the hour in response to changing wind conditions. Natural Gas argues 

that strict adherence to cost causation principles is central to ensuring that the proposals 

are limited to removing barriers and do not have the unintended consequence of 

subsidization and, ultimately, departure from the central precept of fuel neutrality. 

122. Montana PSC states that traditional generation choosing to utilize intra-hour 

scheduling should be allocated a portion of implementation costs; however, absent this 

election VERs should be responsible for all costs related to development, operations, and 

maintenance of intra-hour scheduling.162 NRECA similarly contends that, if transmission 

customers other than VERs make use of the new scheduling regime, it would be 

appropriate for those entities to share in the cost through Schedule 1 charges. Grant PUD 

argues that there is no guarantee that other resources may benefit from a shorter 

scheduling period and that some resources may actually incur costs to maintain 15-

minute schedules, in which case they would pay twice for the shift to shorter schedules. 

 162 Similarly, NorthWestern asserts that unless intra-hour scheduling is made 

mandatory for all transmission customers, the VERs opting to use intra-hour scheduling 

should pay for the increased scheduling flexibility and the non VER customers should not 

be required to subsidize any particular generator type. 
Docket No. RM10-11-000 - 98 -

123. Avista asserts that allowing recovery through Schedule 1 will allocate costs not 

only to all transmission customers, but also to bundled retail native load customers. 

Avista argues that native load customers achieve no cost savings when a VER is located 

within a balancing authority area and is used to serve load within the same balancing 

area. Avista states that in this situation the native load customers bear all of the costs 

associated with following the output of the VER and do not need or benefit from intrahour scheduling. Thus, Avista requests that none of the costs of implementing intra-hour 

scheduling be borne by a transmission provider’s bundled retail native load customers.

124. Several of these commenters recommend that the Commission consider other 

mechanisms for recovering the costs of implementing intra-hour scheduling as opposed 

to a broad cost allocation scheme through Schedule 1.163 For example, Avista asks the 

Commission to allow a transmission provider to directly assign the costs of implementing 

these reforms to the VER transmission customers that are the cause of such reforms 

through an appropriate charge included in either Schedule 1 or Schedule 10. NRECA 

argues that there is more than one method that a public utility transmission provider could 

use to recover costs and requests that the Commission provide public utility transmission 

providers the flexibility to choose the method that works best for each system and 

demonstrate a just and reasonable rate pursuant to section 205 of the FPA. NRECA also 

 163 E.g., Avista; Grant PUD; NRECA; Puget.
Docket No. RM10-11-000 - 99 -

urges the Commission to include costs incurred to comply with any new Reliability 

Standards that ensue from the Final Rule. 

iii. Commission Determination

125. The Commission adopts its proposal and allows public utility transmission 

providers to recover any costs incurred to implement the intra-hour scheduling reforms 

adopted in this Final Rule pursuant to Schedule 1 of the transmission provider’s OATT. 

The Commission is not persuaded by commenters opposing the proposal that recovery of 

these costs through Schedule 1 will result in an overly broad assignment of costs. Such 

commenters argue that only a subset of transmission customers is likely to use intra-hour 

scheduling and that only those customers should bear the cost of implementing intra-hour 

scheduling reforms. The Commission disagrees. As discussed above, intra-hour 

scheduling provides all transmission customers with the tools needed to mitigate 

exposure to Schedule 9 generator imbalance charges in light of changing conditions.164 

Implementation of intra-hour scheduling is also necessary to the extent sellers wish to 

develop intra-hour energy products to maximize the value of available resources or to 

allow load serving entities to lower purchased power costs.165 The Commission finds 

that these benefits will be spread broadly across customer classes. 

 164 See supra § IV.A.1 (Intra-Hour Scheduling Requirement).

165 Id.
Docket No. RM10-11-000 - 100 -

126. Moreover, commenters opposing the Commission’s proposal fail to reconcile their 

position with existing approaches used to recover scheduling-related costs under 

Schedule 1 of the pro forma OATT. Transmission providers do not currently parse 

scheduling costs into, for example, categories for network customers and point-to-point 

customers even though at times scheduling reforms have focused on one set of customers 

and not the other.166 Rather, transmission customers as a whole have allocated the costs 

of scheduling-related activities through Schedule 1: Scheduling, System Control and 

Dispatch Service, and relevant allocations to retail native load have been made by public 

utility transmission providers. Commenters have failed to justify why the Commission 

should depart from this precedent during implementation of intra-hour scheduling 

practices.

127. In response to NRECA, the Commission’s focus in this proceeding is on the 

implementation of intra-hour scheduling and, as relevant here, the recovery of 

scheduling-related implementation costs pursuant to Schedule 1 of the pro forma OATT. 

The Commission did not propose to address, and does not address here, recovery of other 

costs associated with compliance with NERC Reliability Standards.

 166 See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 770.
Docket No. RM10-11-000 - 101 -

c. Clarify Proposed Rule Language

i. Comments

128. Commenters ask the Commission to clarify what is intended by the terms schedule 

and scheduling interval. Southern and EEI state that the term “schedule” is not well 

defined throughout the electric industry and requests that the Commission clarify that 

“schedule” is equivalent to “Interchange Transaction” in the NERC Reliability Standards 

Glossary of Terms. TVA suggests that “scheduling intervals” coincide with the “ramp 

start” times as defined in the Timing Requirements tables of the NERC Reliability 

Standards INT-005-3, Interchange Authority Distributes Arranged Interchange; INT-006-

3, Response to Interchange Authority; and INT-008-3, Interchange Authority Distributes 

Status. TVA contends that to view the term “scheduling interval” otherwise would 

deviate from NERC Reliability Standards and potentially have an adverse effect on 

assessment periods for reliability.

129. Bonneville Power requests that the Commission clarify the responsibilities of 

source and sink balancing authorities in regards to holding contingency reserves 

associated with scheduling of VER generation. Bonneville Power states that there is a 

debate regarding whether and when a source or sink balancing authority should deploy 

contingency reserves when a VER scheduling error exhausts the available balancing 

reserve capacity. Bonneville Power asks the Commission to clarify that a transmission 

provider can establish a base obligation to provide balancing reserve capacity to balance 

VERs and that the transmission provider can negotiate options for additional service 

beyond the base obligation with individual transmission customers. 
Docket No. RM10-11-000 - 102 -

130. A few commenters request clarification of the appropriate curtailment priority for 

intra-hour transmission schedules under the proposed reform.167 Specifically, these 

commenters inquire as to whether a firm transmission reservation that is scheduled for 

less than the full hour would have priority over a non-firm hourly schedule. Bonneville 

Power and NRECA contend that submission of a firm intra-hour schedule should not 

necessarily result in the curtailment of lower priority hourly schedules. MidAmerican 

requests that the Commission clarify whether the submission of an intra-hour schedule by 

a transmission customer with firm transmission rights, after a competing intra-hour 

schedule from a transmission customer with only non-firm transmission rights, has 

curtailment priority.

131. Other commenters question how ATC calculations should be performed after 

implementation of intra-hour scheduling.168 Public Interest Organizations state that 

current policy in the West does not allow ATC associated with transmission reservations 

that are not scheduled day-ahead to be used by other customers. Public Interest 

Organizations suggest that this policy may severely constrain or prohibit the effectiveness 

of intra-hour scheduling. In addition, Tacoma Power suggests that it may be appropriate 

to align ATC calculations with intra-hour scheduling intervals. Invenergy Wind asserts 

that the entire operational construct needs to shift from an hourly to a 15-minute basis in 

 167 E.g., Bonneville Power; EEI; MidAmerican; NRECA.

168 E.g., Public Interest Organizations; Tacoma Power. 
Docket No. RM10-11-000 - 103 -

order to increase the efficiency of operating the transmission system and acquiring 

sufficient reserves in order to integrate VERs on a non-discriminatory basis. However, 

NorthWestern argues that continued use of hourly transmission service reservations 

would not be inconsistent with implementation of intra-hour transmission scheduling, 

stating that administering intra-hour transmission reservations would be difficult and 

costly.

132. Grant PUD makes reference to the Commission’s use of the term “reasonable 

control” in the Proposed Rule, where the Commission states that it is unduly 

discriminatory to continue to require a resource to match an hourly schedule, especially 

when the output of the resource fluctuates beyond its reasonable control.169 Grant PUD 

contends that what is reasonable depends on the current state of technology and requests 

that the Commission clarify that the definition of “reasonable control” is expected to 

improve over time.

ii. Commission Determination

133. In response to Southern and EEI, the Commission clarifies that the term 

“schedule” as used in this Final Rule is equivalent to its use in Schedule 9 of the OATT: 

“...a delivery schedule from [a] generator to (1) another Control Area or (2) a load within 

the Transmission Provider’s Control Area.”170 The procedures for submitting and 

 169 Grant PUD (citing Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 39).

170 OATT Schedule 9.
Docket No. RM10-11-000 - 104 -

revising a transmission schedule are delineated in sections 13.8 and 14.6 of the pro forma 

OATT, as changed by this Final Rule. Any transmission service schedule currently 

submitted pursuant to OATT sections 13.8 and 14.6 can therefore be modified or created 

in 15-minute intervals under this Final Rule. 

134. In response to TVA, the Commission clarifies that the 15-minute scheduling 

interval will be treated the same as the current one-hour scheduling interval with respect 

to ramp start and stop times as defined in the Timing Requirements tables of NERC 

Reliability Standards INT-005-3, INT-006-3, and INT-008-3. As an example, in the 

Eastern Interconnection ramp start times will begin five minutes before the start of the 

15-minute scheduling interval and end five minutes after the start of the 15-minute 

scheduling interval. 

135. Regarding responsibilities for holding contingency reserves, the Commission did 

not propose any changes to existing rules regarding the use of contingency reserves in 

this proceeding. As Bonneville Power notes, there is ongoing debate in the industry 

regarding when and how contingency reserves may be used under NERC Reliability 

Standards. The Commission concludes it is appropriate, in the first instance, for 

stakeholders to address these questions through the NERC processes.171

 171 The Commission addresses requests by Bonneville Power and others to limit 

the amount of capacity it must make available to transmission customers for generator 

regulation service under Schedule 10 in § IV.C.1 (Schedule 10-Generator Regulation and 

Frequency Response Service) below. 
Docket No. RM10-11-000 - 105 -

136. The Commission also did not propose any changes to curtailment policies or ATC 

calculation. The Commission recognizes that transmission providers have flexibility 

under the pro forma OATT to award transmission service based on transmission 

capability that becomes available when firm transmission service is not scheduled by 

10:00 am the day prior to operation.172 The Commission appreciates that, when a 

transmission provider makes service available under these circumstances, application of 

curtailment priorities and ATC calculation rules become more complicated. However, 

that is already the case under hourly transmission schedules. Therefore, the Commission 

did not propose any change to those practices to accommodate the possibility of intrahour transmission schedules. All transmission schedules for firm service will continue to 

have curtailment priority over all transmission schedules for non-firm service173 and 

transmission providers will continue to be required to follow existing rules governing the 

calculation of ATC.174

 172 The pro forma OATT states that “[s]chedules for the Transmission Customers’ 

Firm Point-To-Point Transmission Service must be submitted no later than 10:00am...of 

the day prior to commencement of such service.” OATT Schedule 13.8. 

173 The pro forma OATT makes clear that “(p)arties requesting Non-Firm PointTo-Point Transmission Service for the transmission of firm power do so with the full 

realization that such service is subject to availability and to Curtailment or Interruption 

under the terms of the Tariff.” OATT Schedule 14.5.

174 In compliance with Order No. 890, public utility transmission providers have 

documented rules governing their calculation of ATC in Schedule C of their OATTs. See

Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 193.
Docket No. RM10-11-000 - 106 -

137. In response to the request from Grant PUD for clarification of the term “reasonable 

control,” the Commission explains that use of the term “reasonable control” is not 

intended to be a metric or a determining factor, but illustrative of the difficulty VERs 

experience when attempting to follow hourly schedules accurately. The Commission 

does not find it necessary to offer any further clarification.

d. NERC and NAESB Standards

i. Commission Proposal

138. In the Proposed Rule, the Commission noted that many commenters, in response 

to the NOI, claimed that shorter scheduling intervals may enhance reliability. The 

Commission therefore stated that it did not believe that an independent review of NERC 

Reliability Standards is necessary in order to propose implementation of intra-hour 

scheduling. However, the Commission sought comment on the issue to ensure that there 

is no inconsistency between relevant NERC standards and the proposed intra-hour 

scheduling tariff reform.175 

ii. Comments

139. NERC states that certain entities currently offer 15-minute scheduling and that it is 

unaware of any conflicts with Reliability Standards. However, NERC asserts that wide 

spread use of intra-hour scheduling will likely require review and refinement of several 

existing Reliability Standards. Based on its preliminary review of Reliability Standards 

 175 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 37.
Docket No. RM10-11-000 - 107 -

in coordination with industry stakeholders, NERC states that it does not believe there are 

any insurmountable hurdles that prevent industry from implementing 15-minute 

transmission scheduling. NERC explains that sufficient time must be allowed for 

Reliability Standards to be modified through the NERC Reliability Standards Committee 

prioritization process, but that transitioning to broad intra-hour scheduling flexibility is 

achievable in a reasonable timeframe. 

140. Some commenters do not anticipate that a review of NERC Reliability Standards 

is necessary to ensure reliability upon the implementation of intra-hour scheduling.176 

NaturEner argues that an independent review of NERC standards may not be necessary, 

but if such a review occurs it should not delay implementation of intra-hour scheduling. 

Pacific Gas & Electric agrees that implementation of intra-hour scheduling can be 

achieved without a review of NERC standards, but recommends that NERC and other 

industry experts review and update current planning and operating criteria to ensure that 

balancing authorities have the necessary tools to flexibly balance loads and resources 

with the advent of increased VER penetration.

141. Other commenters contend that review and modification of standards may be 

necessary, but not a prerequisite to implementation.

177 Southern and Xcel state that only 

modest, if any, changes would be needed to NERC Reliability Standards. Southern 

 176 E.g., NaturEner; Southern California Edison.

177 E.g., NERC; Pacific Gas & Electric
Docket No. RM10-11-000 - 108 -

indicates that several standards may need to be reviewed and revised as they currently 

contemplate hourly intervals. Xcel contends that standards related to the maximum lead 

times required for entry and approval of a schedule may require changes. Xcel explains 

that the lead times for entry and approval of a tag may exceed the length of a scheduling 

interval, thus diminishing the usefulness of intra-hour scheduling. AEP and Duke Energy 

suggest that sensitivity studies should be performed by an industry forum or working 

group to determine the reliability impacts of the proposed scheduling changes on realtime system operations.

142. Several commenters argue that review and revision of NERC Reliability 

Standards, as well as NAESB business practice standards, may be necessary for the 

implementation of intra-hour scheduling at 15-minute intervals.178 These commenters 

point out that many Reliability Standards and business practices are largely predicated on 

hourly scheduling intervals and govern transactions both internal to a particular balancing 

authority as well as across neighboring balancing authorities. Although most 

commenters did not identify specific changes to standards that would be necessary, some 

commenters suggest that NERC Reliability Standards related to some or all of the 

following areas be reviewed: Interchange Scheduling and Maintenance Coordination 

(INT), Resource and Demand Balancing (BAL), Emergency Preparedness and 

 178 E.g., Bonneville Power; Duke; EEI; MidAmerican; NRECA; PNW Parties; 

Southern.
Docket No. RM10-11-000 - 109 -

Operations (EOP), and Transmission Operations (TOP) standards.179 Additionally, 

commenters indicate that reliability scheduling tools, such as the Interchange Distribution 

Calculator used in the Eastern Interconnection and the WebSAS system used in the 

Western Interconnection for scheduling, curtailment and “check out” processes may also 

require modification.180 

143. NRECA cautions that any modifications to NERC standards should allow for the 

implementation of intra-hour scheduling but not mandate this practice. NRECA suggests 

that NERC be allowed to complete any updates to its standards associated with 

implementation of intra-hour scheduling prior to NAESB undertaking a review to ensure 

uniformity of approaches. NV Energy notes that, in order to schedule at 30 minute 

intervals or less, the protocols to effectuate such transactions must be agreed upon by all 

entities in WECC. Therefore, NV Energy requests that the Commission defer issuance of 

the Final Rule until the industry has had the opportunity to address NERC, WECC and 

NAESB standards issues. 

144. PNW Parties state that the Joint Initiative participants found it necessary to review 

NERC and NAESB standards as part of their development of a 30-minute scheduling 

program, but did not identify in comments whether any changes to standards or business 

practices were needed. PNW Parties suggests, however, that applicable standards and 

 179 E.g., Duke; EEI; NERC; NRECA; PNW Parties; Southern.

180 E.g., NERC; NRECA; Southern.
Docket No. RM10-11-000 - 110 -

business practices be reviewed and revised as necessary prior to implementing more 

granular scheduling. 

145. Some commenters within the VER industry request clarification and/or 

modification of NERC scheduling protocols to allow for a resource to be indentified as a 

“sink.”181 These commenters claim that this is necessary because under the 

Commission’s proposed reforms VERs will be transacting on an intra-hour basis in order 

to supplement their variable supply. Iberdrola explains that, in order to enter into 

bilateral transactions for balancing energy where a VER’s 15-minute schedule is less than 

its hour-ahead schedule, the additional balancing energy purchased from a generator with 

excess energy would need to be tagged as the “source” and the VER would need to be 

tagged as the “sink.” Iberdrola claims that this is necessary because VERs will be 

transacting bilaterally in the sub-hourly timeframe in an effort to maintain the schedule 

that was entered prior to the operating hour. AWEA agrees, arguing that some of the 

benefits of intra-hour scheduling will not be realized without this additional clarification. 

In response to the potential concerns of transmission providers regarding generators 

being tagged as sinks, AWEA and Iberdrola argue that reliability concerns would only be 

present when the ultimate delivery point is unknown.182 AWEA explains that the case 

presented by a VER transacting as a sink for intra-hour scheduling purposes is entirely 

 181 E.g., AWEA; Iberdrola.

182 E.g., AWEA; Iberdrola.
Docket No. RM10-11-000 - 111 -

different, as the ultimate delivery point is already known. In this case, AWEA points out 

that there is a schedule to deliver energy to a real load and explains that this schedule is 

delivering energy to the load which the VER is unable to serve. Therefore, AWEA and 

Iberdrola conclude that such scheduling practices do not present reliability concerns.

iii. Commission Determination

146. The Commission concludes that an independent review of NERC standards and 

NAESB business practices is not necessary prior to the implementation of intra-hour 

scheduling. As noted by NERC, several entities currently offer intra-hour scheduling 

without any apparent conflict with Reliability Standards. NERC comments that it does 

not believe there are any existing standards that prohibit industry from implementing 

intra-hour scheduling, and no commenters have pointed to specific NAESB business 

practices that prevent industry from implementing intra-hour scheduling. The 

Commission therefore concludes that it is not necessary to delay adoption of the intrahour scheduling requirements of this Final Rule pending further review of NERC 

Reliability Standards and NAESB business practices. To the extent industry believes it is 

beneficial to refine one or more existing NERC Reliability Standards or NAESB business 

practices to reflect intra-hour scheduling, stakeholders can use existing processes to 

pursue such refinements. 

147. With regard to the requests from AWEA and Iberdrola to allow a VER resource to 

be designated as a “sink” for purposes of transmission scheduling, rules for scheduling 
Docket No. RM10-11-000 - 112 -

transmission segments are set forth in NAESB’s Coordinate Interchange Standards,183

which have been incorporated into the Commission’s regulations by reference.184 The 

Proposed Rule did not propose any changes to those rules and the Commission declines 

to interpret the application to any particular transactions in this generic rulemaking 

proceeding.

3. Other Issues

a. Comments

148. Several commenters question the application of intra-hour scheduling reforms to 

HVDC transmission lines. Clean Line states that HVDC transmission lines can precisely 

control power and, thus, are typically expected to submit schedules to public utility 

transmission providers. Clean Line requests that HVDC transmission lines receive equal 

treatment and be allowed to submit intra-hour schedules on the same basis as generators. 

In contrast, ALLETE and Midwest ISO Transmission Owners both request that the 

Commission grant an exemption from 15-minute schedules for HVDC transmission lines. 

These commenters argue that 15-minute scheduling of HVDC transmission lines could 

lead to an increase in the duty on the load tap changers of HVDC converter transformers, 

potentially resulting in an increase in maintenance costs and an increased potential of 

transformer failure. 

 183 NAESB WEQ-004, App. C, § 2 (Commercial Timing Table).

184 See 18 CFR § 38.2 (2011).
Docket No. RM10-11-000 - 113 -

149. Bonneville Power raises questions regarding the impact of intra-hour scheduling on 

dynamic scheduling practices. Bonneville Power states that 15-minute scheduling will 

lead to increased ramping and inhibit the availability of dynamic transfer capability in 

areas where dynamic transfer capability is limited, such as the Bonneville Power system 

and other parts of the West. Bonneville Power contends that 30-minute scheduling 

relieves this problem and requests that the Commission gain a better understanding of the 

impacts that 15-minute scheduling will have on dynamic transfers. In contrast, First 

Wind requests that the Commission encourage dynamic transfers in addition to 

implementing intra-hour scheduling, suggesting that dynamic transfers can reduce 

regulation service requirements for transmission owners and transfer regulation 

requirements to purchasers of VER energy. First Wind also argues that intra-hour 

scheduling and dynamic transfers will allow for better tracking of real-time generation 

and reduce the need for ancillary services while increasing opportunities for flexible 

generation and demand response.

150. M-S-R Public Power Agency states that shortening the scheduling interval does not 

reduce the intermittency of the VERs themselves. M-S-R Public Power Agency offers 

that as a matter of physics a VER requires a back-up resource to “balance” its 

intermittency, irrespective of scheduling, adding that while a shorter scheduling interval 

may mitigate the number of megawatts needed to assure reliability, it will not mitigate 

the location or cost of back-up reserves. M-S-R Public Power Agency goes on to state 

that VER penetration levels of 20-25 percent start to exhaust the capability of even the 

most robust systems and that the proposed mitigation may be insufficient. M-S-R Public 
Docket No. RM10-11-000 - 114 -

Power Agency explains that the raw energy of VERs must be converted to conditioned 

energy (traditional resources) at the source, and not shifted to other locations through 

mitigation, or there will be a degradation of services to all VERs within that system. MS-R Public Power Agency states that intermittent resources require that the transmission 

owner have nearly infinite capability to provide backup resources; however, even the 

most robust balancing authority has limitations of how fast, how often, and when it can 

provide back up resources. M-S-R Public Power Agency offers that, with both the cost 

of transmission and reliability (back-up generation) challenges, VERs may be 

uneconomic. M-S-R Public Power Agency encourages the Commission to solicit input 

on this issue. 

Commission Determination

151. All transmission customers that are currently eligible to submit hourly energy

schedules will be eligible to participate in intra-hour scheduling, including HVDC lines 

that currently submit hourly energy schedules. To the extent a transmission provider 

believes an exemption is appropriate, it has the right to request a waiver of all or part of 

the OATT requirements as described in 18 CFR § 35.28(d): “A public utility subject to 

the requirements of this section and Order No. 889, FERC Stats. & Regs. ¶31,037 (Final 

Rule on Open Access Same-Time Information System and Standards of Conduct) may 

file a request for waiver of all or part of the requirements of this section, or Part 37 (Open 

Access Same-Time Information System and Standards of Conduct for Public Utilities), 

for good cause shown.” Waiver requests will be evaluated in separate proceedings if and 

when they are submitted based on the facts and circumstances of each request.
Docket No. RM10-11-000 - 115 -

152. With regard to the use of dynamic schedules, the Commission did not propose and 

is not adopting any change in policy with regard to dynamic scheduling. The

Commission is not persuaded by arguments from Bonneville Power that 15-minute 

scheduling intervals will negatively affect dynamic transfer capability. However, the 

Commission acknowledges that a transmission provider’s implementation of charges for 

generator regulation service, as discussed in the following section, may have the result of 

encouraging the use of dynamic scheduling to avoid such charges. 

153. In response to M-S-R Public Power Agency, the Commission appreciates that the 

location of a particular resource can be relevant in determining whether it can be used to 

satisfy reserve obligations. That is, a public utility transmission provider providing 

ancillary services under the pro forma OATT, or a transmission customer self-supplying 

such ancillary services needs transmission capacity to ensure deliverability of a particular 

resource. Whether that is the case will be fact specific and we expect the transmission 

provider to take the appropriate steps to ensure such transmission capacity is available. 

B. Data Reporting to Support Power Production Forecasting

154. The second of the two reforms adopted in this Final Rule relates to the submission 

of meteorological and forced outage data,185 by new interconnection customers whose 

 185 The Proposed Rule used the term “operational data” and specified forced 

outages as a particular type of operational data. To reflect the limited nature of data to be 

reported under this Final Rule more accurately, the Commission instead refers more 

specifically to “forced outage data” in our determinations here and accompanying 

revisions to the pro forma LGIA. We also note that Section 9.7.1 of the LGIA requires 

Transmission Providers and Interconnection Customers to coordinate and report planned 

 

(continued...)
Docket No. RM10-11-000 - 116 -

generating facilities are VERs, to the public utility transmission provider with which the 

customer is interconnected if the public utility transmission provider is doing power 

production forecasting. As discussed below, the Commission amends the pro forma 

LGIA to effectuate this data reporting requirement. The Commission concludes that, 

without these reporting requirements in place, 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. 

1. Data Requirements

a. Commission Proposal

155. To facilitate the development and deployment of power production forecasting by 

public utility transmission providers, the Proposed Rule set forth revisions to the pro 

forma LGIA that would require interconnection customers whose generating facilities are 

VERs to provide certain meteorological and operational data to the public utility 

transmission provider with whom they are interconnected, if doing forecasting. The 

Commission proposed that such data would be transmitted from the interconnection 

customer to the public utility transmission provider at or near real-time. The Commission 

stated that this proposal built on existing Commission data-sharing requirements by 

 

outages. Within the context of this Final Rule, the Commission references the term 

“forced outage” as defined by NERC. See NERC Glossary of terms available at

http://www.nerc.com/files/Glossary_of_Terms.pdf.
Docket No. RM10-11-000 - 117 -

outlining specific meteorological and operational data necessary to develop power 

production forecasts.186

156. With regard to the reporting of meteorological data, the Commission proposed 

revisions to the pro forma LGIA that would result in different types of meteorological 

information being provided by interconnection customers based on the type of VER they 

own and/or operate. The Commission proposed to require interconnection customers 

whose generating facilities are wind-based VERs to provide public utility transmission 

providers with site-specific meteorological data including, but not limited to, 

temperature, wind speed, wind direction, and atmospheric pressure. The Commission 

proposed to require interconnection customers whose generating facilities are solar-based 

VERs to provide public utility transmission providers with site-specific meteorological 

data including, but not limited to, temperature, atmospheric pressure, and cloud cover. 

The Commission recognized that different power production forecasts may require 

meteorological instruments to be located at hub height, up-wind of resources, or at 

ground level. However, the Commission refrained from proposing specific requirements 

in this respect and, instead, proposed to allow the public utility transmission provider and 

interconnection customers to negotiate these details taking into account the size and 

configuration of the VER facility, its characteristics, location, and importance in 

maintaining generation resource adequacy and transmission system reliability in its area. 

 186 See Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at PP 60-61.
Docket No. RM10-11-000 - 118 -

The Commission stated that resource-specific data requirements contained in individual 

LGIAs must be negotiated on a not unduly discriminatory basis.187

157. With respect to the reporting of operational data, the Commission proposed to 

revise the pro forma LGIA to require interconnection customers whose generating 

facilities are VERs to report to the public utility transmission provider any forced outages 

that reduce the generating capability of the resource by 1 MW or more for 15 minutes or 

more. The Commission noted that provision of VER outage data at this level of 

granularity would allow a public utility transmission provider to ascertain the extent to 

which current VER power production is a result of unit availability as opposed to 

changing weather conditions.188 The Commission preliminarily found that having such 

information would eliminate a significant source of forecasting errors by ensuring that the 

public utility transmission provider has accurate information regarding the capacity 

actually available to produce electricity during the time-frame of the operational 

forecasts.189

 187 See id. P 61.

188 See id. P 62 (citing Cal. Indep. Sys. Operator Corp., 131 FERC ¶ 61,087, at 

P 64 (2010)).

189 Id. P 62.
Docket No. RM10-11-000 - 119 -

158. The Commission sought comment on the extent to which the lists of basic 

meteorological and operational data articulated above may be inadequate or incomplete 

in achieving the stated power production forecasting goals.190

b. Comments

159. Commenters addressing the reporting of meteorological data generally support 

requiring the provision of data as necessary to enable public utility transmission providers 

to employ power production forecasts.191 While disagreeing that public utility 

transmission providers should be responsible for power production forecasting, Montana 

PSC argues that, should the Commission impose forecasting requirements, public utility 

transmission providers should have access to all meteorological data that are site-specific 

to the VER, provided that the parties have a confidentiality agreement in place to protect 

proprietary information. BP Companies and First Wind request that the Commission 

clarify that the proposal is only relevant to instances in which the public utility 

transmission provider is developing and/or implementing VER power production 

forecasting.

 190 Id. P 63.

191 E.g., AWEA; Bonneville Power; California ISO; CEERT; Clean Line; 

California PUC; Exelon; First Wind; Iberdrola; Independent Energy Producers; 

Independent Power Producers Coalition-West; ISO/RTO Council; ISO New England; 

Large Public Power; Midwest ISO; Midwest ISO Transmission Owners; NaturEner; 

NextEra; NRECA; Pacific Gas & Electric; PJM; Powerex.
Docket No. RM10-11-000 - 120 -

160. Several commenters support the Commission’s identification of certain categories 

of meteorological data to be provided by wind and solar resources.192 For example, with 

regard to wind resources, Iberdrola agrees that wind speed, wind direction, temperature 

and pressure are all key atmospheric variables related to wind farm output and are the 

most important fields to measure. With regard to solar resources, NextEra, SEIA, and 

Xcel generally support the minimum categories of data identified in the Proposed Rule, 

but they suggest that the Commission revise the reference to cloud cover because it is 

ambiguous. Specifically, NextEra and SEIA recommend that the Commission require 

solar resources to report diffuse, direct, and global horizontal irradiance. NextEra adds 

that humidity should also be provided for a solar VER using concentrating thermal solar 

technology, while SEIA suggests that plane of array irradiance or direct normal radiation 

may also be necessary. These commenters note that irradiance is often a better measure 

because it actually drives energy production.

161. Commenters generally support the Commission’s proposal to allow the public 

utility transmission provider and interconnection customer to negotiate additional 

meteorological and operational data reporting requirements.193 Commenters identified a 

variety of additional meteorological and facility-specific data that may be useful in 

developing and deploying power production forecasts. These commenters generally note 

 192 E.g., AWEA; Iberdrola; ISO New England; RENEW.

193 E.g., Bonneville Power; ISO New England; ISO/RTO Council; Large Public 

Power Council; Midwest ISO; NRECA; PNW Parties; RENEW; Xcel.
Docket No. RM10-11-000 - 121 -

that regional differences may dictate additional data needs,194 with several asking the 

Commission to acknowledge that additional data beyond that specifically identified in the 

Proposed Rule may be needed by a public utility transmission provider.195

162. Several commenters raise concerns regarding the Commission’s discussion of the

location of meteorological towers and other equipment necessary to record and report 

data to public utility transmission providers.196 NextEra asks that the Commission refrain 

from allowing public utility transmission providers to require VERs to install multiple 

meteorological towers, arguing that data beyond what is available through one 

meteorological tower has little value for advanced power production forecasting methods. 

Invenergy similarly argues that a single meteorological tower per facility is usually 

sufficient for predicting plant output. 

163. With regard to the frequency of reporting meteorological data, several commenters 

suggest that the frequency of data reporting should match the use of the data, which may 

not be at or near real-time.197 For example, AWEA, Iberdrola, and NextEra state that 

second-by-second or minute-by-minute meteorological recordings yield minimal benefits 

 194 E.g., Bonneville Power; First Energy; ISO New England; ISO/RTO Council; 

NextEra; MidAmerican; Midwest ISO; Midwest ISO Transmission Owners; 

NorthWestern; NRECA; Pacific Gas & Electric; Xcel.

195 E.g., Bonneville Power; ISO New England; Midwest ISO; NextEra; NRECA.

196 E.g., AWEA; Invenergy; NextEra.

197 E.g., AWEA; Clean Line; Iberdrola; NextEra; NaturEner; NorthWestern; 

Public Interest Organizations.
Docket No. RM10-11-000 - 122 -

for forecasting accuracy and could be costly and burdensome. AWEA and Clean Line 

suggest that a reasonable requirement for the frequency at which real-time meteorological 

and operational data is reported from a wind plant is 10 minutes or more. NorthWestern, 

however, states that it would be helpful to require each VER to update the forecasting 

data that it has provided to the public utility transmission provider when it provides a new 

energy schedule. 

164. AWEA and Iberdrola also contend that distinctions should be made between the 

types of data that should be provided in real-time and the types of data that should be 

provided historically. These commenters state that archived time series data are crucial 

to statistical forecasting techniques and that this application is not done in real-time. 

AWEA and Iberdrola state that data needed for forecast training can be compiled into 

larger datasets and transmitted at less frequent intervals at a much lower cost. 

RenewElec and Bonneville Power generally agree that there is significant value in 

historical data recorded by VERs. 

165. With regard to the operational data reporting requirements, some commenters urge 

the Commission to adopt the proposed requirement that VERs report to the public utility 

transmission provider any forced outages that reduce the generating capacity of a 

resource by 1 MW or more for 15 minutes or more.198 For example, Bonneville Power 

states that having access to forced outage information will enable public utility 

 198 E.g., Bonneville Power; California ISO; NRECA.
Docket No. RM10-11-000 - 123 -

transmission providers to determine whether forecast inaccuracy results from unit 

availability, changing weather conditions, or a combination of the two. Bonneville 

Power further states that without such information it will be difficult to verify forecasts 

and improve forecast accuracy. California ISO requests that the Commission not 

overturn its recent decision approving California ISO’s 1 MW threshold for reporting a 

forced outage of an eligible intermittent resource. California ISO argues that outage 

reporting requirements that are less stringent than those proposed would increase the 

likelihood that the forecasting algorithm would accumulate inaccurate data. 

166. Other commenters acknowledge that forced outage data are useful in developing 

power production forecasts, but disagree on the exact reporting requirements.199 Some 

commenters contend that a 1 MW reporting threshold would pose an unnecessary burden 

on a wind plant owner/operator, yield minimal benefits for forecast accuracy, and pose 

compliance difficulties.200 Instead of the proposed requirement, NaturEner recommends 

requiring that only planned outages of greater than 15 percent of the generator’s capacity 

should be reported as soon as they are known by the generator. AWEA suggests that 

reporting apply only to forced outages that exceed 10 percent of the nameplate capacity 

of a plant, a requirement that AWEA states is similar to the one imposed on conventional 

generators. NextEra similarly asks that the outage reporting requirements be identical to 

 199 E.g., AWEA; Exelon; NaturEner; SEIA; Xcel; MidAmerican; NextEra.

200 E.g., AWEA; Iberdrola; NaturEner; MidAmerican; PJM.
Docket No. RM10-11-000 - 124 -

those that apply to conventional resources. MidAmerican recommends that VER 

transmission customers be required to report forced outages lasting more than 24 hours 

and involving the lesser of either 20 MW or 50 percent of nameplate capacity. Xcel 

recommends that the Commission ask NERC to analyze and determine the appropriate 

threshold level for reporting VER outages to public utility transmission providers and 

balancing authorities.

167. SEIA contends that the forced outage reporting requirement may be appropriate 

for large solar photovoltaic generators, but not for concentrating solar plants that 

experience frequent changes in power output. SEIA states that, with respect to 

concentrating solar power-generating facilities, the Commission should consider a 

threshold for reporting such fluctuations based either on the total capacity of the facility 

or particular types of maintenance or repair activities that would result in an outage at a 

percentage of the facility.

168. Exelon asks the Commission to clarify what constitutes a forced outage for 

purposes of the requirement to report operational data, suggesting it should only include 

unanticipated outage events. NRECA notes that the Proposed Rule did not identify the 

frequency for reporting operational data to the public utility transmission provider. 

NRECA contends that the public utility transmission provider should be notified as soon 

as the VER is aware of an outage. 
Docket No. RM10-11-000 - 125 -

169. Several commenters recommend that the Commission provide regional flexibility 

with respect to the operational data reporting requirements.201 For example, Iberdrola 

states that VER forced outage reporting requirements should be regional and: (1) based

on the penetration of VERs in the region; (2) based on the ability of the transmission 

provider to incorporate the data into power production forecasting from VERs that is in 

turn used for reliably operating the system; and (3) limited to an interval that enables the 

use of predictive outage reporting capability. 

170. Some commenters argue that the Commission should acknowledge the 

importance of standardized regional reporting mechanisms when considering these 

proposed reforms.202 For example, Midwest ISO notes that IEC Standard 61400-25 

already exists to facilitate the exchange of information between individual wind turbines, 

their constituent components, wind power plants, area control, and other external 

systems. Midwest ISO suggests that use of a common format for communicating data 

between the VER and public utility transmission provider would promote the 

development of power production forecasting. However, Invenergy asks that the 

Commission make clear that public utility transmission providers are required to accept 

reasonable alternative means of data communication and not implement uniform 

standards that impose unnecessary costs on wind projects. 

 201 E.g., Iberdrola; ISO New England; Midwest ISO Transmission Owners; PJM; 

Southern California Edison.

202 E.g., Alstom; EEI; Midwest ISO.
Docket No. RM10-11-000 - 126 -

c. Commission Determination 

171. The Commission adopts, as modified below, the proposed requirement that 

interconnection customers whose generating facilities are VERs 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. As discussed below, power 

production forecasting can be used by public utility transmission providers to operate 

their systems and manage reserves more efficiently. To the extent a public utility 

transmission provider seeks to rely on power production forecasting, the Commission 

concludes it is appropriate to require new interconnection customers whose generating 

facilities are VERs to provide related data to the public utility transmission provider 

under the circumstances below. The Commission therefore directs public utility 

transmission providers to modify their pro forma LGIAs to effectuate the data reporting 

requirement.

172. As the Commission noted in the Proposed Rule, industry studies demonstrate the 

potential for significant benefits from the incorporation of power production forecasts 

into scheduling and unit commitment processes. In WECC alone, NREL estimated the 

use of VER power production forecasts has the potential to reduce operating costs by up 
Docket No. RM10-11-000 - 127 -

to 14 percent or $5 billion per year.203 NERC has similarly concluded that forecasting 

the output of variable generation is critical to bulk power system reliability in order to 

ensure that adequate resources are available for ancillary services and ramping

requirements.204 NERC has therefore recommended that forecasting techniques be 

incorporated into day-to-day operational planning and real-time operations 

routines/practices including unit commitment and dispatch.205 The Commission notes 

that the benefits of power production forecasting can accrue across a variety of time 

frames, including the operating day, day-ahead, and seasonally. 

173. However, power production forecasts are only as good as the data on which they 

rely. The ability of public utility transmission providers to use power production 

forecasting in the commitment and de-commitment of resources may be limited without 

adequate meteorological and forced outage data from VERs. The current lack of 

meteorological and forced outage data reporting requirements in the pro forma LGIA 

therefore may limit efforts by public utility transmission providers 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 

 203 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 45 (citing National 

Renewable Energy Laboratory, Western Wind and Solar Integration Study ES-18 (2010), 

available at http://www.nrel.gov/wind/systemsintegration/wwsis.html).

204 NERC, Accommodating High Levels of Variable Generation 54 (2009), 

available at http://www.nerc.com/files/IVGTF_Report_041609.pdf. 

205 Id. at 59.
Docket No. RM10-11-000 - 128 -

transmission providers are permitted to request this information, but there is no obligation 

for interconnection customers whose generating facilities are VERs to provide it. The 

Commission remedies this deficiency by adopting reporting requirements for new 

interconnection customers whose facilities are VERs, commensurate with the power 

production forecasting employed by the public utility transmission provider, to allow for 

more accurate commitment and de-commitment of resources providing reserves, ensuring 

that reserve-related charges imposed on customers remain just and reasonable and not 

unduly discriminatory or preferential. The Commission implements this requirement by 

requiring public utility transmission providers to modify their pro forma LGIAs to 

include the reporting requirements discussed below. 

174. The reporting requirements adopted in this Final Rule are specifically designed to 

support the development and deployment of power production forecasting by public 

utility transmission providers. As a result, nothing in this Final Rule should be construed 

as creating an obligation for interconnection customers whose generating facilities are 

VERs to provide meteorological and forced outage data in cases where the public utility 

transmission provider is not engaging in power production forecasting. The Commission 

recognizes that VER potential and penetration varies across public utility transmission 

provider systems and that, at this time, not all public utility transmission providers have 

sufficient levels of VERs to warrant engaging in power production forecasting. The 

Commission is nonetheless amending the pro forma LGIA to ensure that those public 

utility transmission providers seeking to develop and deploy power production 

forecasting in response to increasing VER penetration have adequate information to do 
Docket No. RM10-11-000 - 129 -

so. To make the conditional nature of the reporting requirements clear, the Commission 

revises the proposed Article 8.4 of the pro forma LGIA to state that all requirements for 

meteorological and forced outage data must be consistent with the power production 

forecasting employed by the Transmission Provider, if any, to manage reserve 

commitments. The Commission believes that this strikes a reasonable balance between 

the requirement to provide the data and the public utility transmission provider’s use of 

the data to manage reserve commitments more efficiently. 

175. Turning to the particular reporting requirements imposed on interconnection 

customers whose generating facilities are VERs, the Commission affirms the approach 

set forth in the Proposed Rule allowing public utility transmission providers flexibility in 

identifying the specific meteorological and forced outage data to be reported. As 

proposed, Article 8.4 of the pro forma LGIA would specify certain categories of data to 

be provided by interconnection customers with VERs having wind or solar as the energy 

source, with the exact specifications of data to be provided taking into account the size 

and configuration of the VER, its characteristics, location, and its importance in 

maintaining generation resource adequacy and transmission system reliability in its area. 

Some commenters generally support this approach, stating that the type of power 

production forecasting deployed by public utility transmission providers and the tools 

used to perform forecasts could vary widely, and therefore any reporting requirements 
Docket No. RM10-11-000 - 130 -

associated with power production forecasting should be flexible.206 This approach will 

provide public utility transmission providers the flexibility to negotiate, in the first 

instance, with interconnection customers whose generating facilities are VERs to identify 

the particular data to be reported by the customer. 

176. The Commission finds that this flexible approach to establishing data reporting 

requirements will ensure that all reporting of meteorological and forced outage data 

corresponds with the power production forecasting being employed by the public utility 

transmission providers. To be clear, however, public utility transmission providers 

cannot unduly discriminate among interconnection customers with regard to data 

reporting requirements. By linking the requirement to provide meteorological and forced 

outage data to the use of these data by the public utility transmission provider in power 

production forecasting to manage reserve commitments, the Commission seeks to 

minimize opportunities for undue discrimination as well as needless burden on 

interconnection customers. At the same time, to the extent meteorological and forced 

outage data are needed for the public utility transmission provider to engage in power 

production forecasting, they must be provided by the interconnection customer, even if 

that means investment in additional equipment by the customer.207 To the extent there 

 206 E.g., Iberdrola; NextEra.

207 The Commission acknowledges the concern of some commenters that the 

installation of multiple meteorological towers would increase costs for an interconnection 

 

(continued...)
Docket No. RM10-11-000 - 131 -

are concerns of discriminatory or unnecessary application of data reporting requirements, 

interconnection customers can request that the public utility transmission provider file 

with the Commission an unexecuted LGIA in order to resolve the disagreement.208

177. Notwithstanding the flexibility provided for party-specific negotiations of data 

reporting requirements, the record in this proceeding also confirms that some categories 

of meteorological data from VERs having wind or solar as the energy source will be 

relevant to most, if not all, power production forecasting deployed by a public utility 

transmission provider for these resources. Therefore, the Commission adopts the 

proposal to require certain categories of meteorological data from VERs having wind or 

solar as the energy source. Specifically, an interconnection customer with a VER having 

wind as the energy source must provide, at a minimum, site-specific meteorological data 

including: temperature, wind speed, wind direction, and atmospheric pressure. An 

interconnection customer with a VER having solar as the energy source must provide, at 

a minimum, site-specific meteorological data including: temperature, atmospheric 

pressure, and irradiance. The exact specifications of data to be provided by the 

interconnection customer will remain subject to negotiation between the parties, which as 

noted above must take into account the size and configuration of the VER, its 

characteristics, location, and its importance in maintaining generation resource adequacy 

 

customer. Whether data from a single meteorological tower is sufficient to support the 

power production forecasting deployed by the public utility transmission provider should 

be addressed as part of the negotiation of the LGIA. 

208 See 16 U.S.C. 824d (2006); 18 CFR 35.13 (2010). 
Docket No. RM10-11-000 - 132 -

and transmission system reliability in its area. It may also include additional 

meteorological data commensurate with the power production forecasting employed by 

the public utility transmission provider. As with other data reporting requirements, the 

public utility transmission provider may file an unexecuted LGIA pursuant to FPA 

section 205 seeking to demonstrate the necessity of requests for additional information if 

the parties cannot reach mutual agreement as to the specifications of data to be 

provided.209

178. By defining certain categories of data that must be provided, while leaving the 

exact specifications of data to negotiation between the interconnection customer and the 

public utility transmission provider, the Commission has sought to balance the competing 

interests of clarity and flexibility. The Commission appreciates that defining all data 

requirements with precision in this Final Rule might result in rules that are easier to 

implement. However, it also could lead to interconnection customers incurring costs to 

provide data at a level of granularity, for example, that is of no use to the public utility 

transmission provider given the type of power production forecasting deployed. By 

linking the reporting requirements to the data needs of the public utility transmission 

provider, the Commission seeks to facilitate the deployment of power production 

forecasting without unduly burdening the interconnection customer. 

 209 Id.
Docket No. RM10-11-000 - 133 -

179. In the Proposed Rule, the Commission included “cloud cover” within the 

categories of data required of interconnection customers with a VER having solar as the 

energy source. The Commission agrees with commenters that the term “cloud cover” is 

imprecise and thus we modify Article 8.4 of the pro forma LGIA to refer to “irradiance.” 

However, the Commission declines to distinguish between types of irradiance and also 

declines to include “humidity” in the minimal categories of data. These additional 

characteristics may be more relevant for some types of facilities than others, so we leave 

to public utility transmission providers and their interconnection customers to identify the 

specifications of data relevant for reporting.

180. With regard to the frequency and timing of data reporting, the Commission 

modifies the Proposed Rule and allows public utility transmission providers and 

interconnection customers whose generating facilities are VERs to negotiate the 

frequency and timing of data submittals. The Proposed Rule would have required the 

reporting of data at or near real-time. In response, commenters such as AWEA and 

Iberdrola note that some power production forecasts use archived time series data that 

may be compiled and transmitted to public utility transmission providers at a significant 

costs savings when compared to the ongoing reporting of data at or near real-time, 

whereas NorthWestern suggests that data could be provided on a ten-minute or longer 

basis. Based on comments received, the Commission concludes it is more appropriate for 

the frequency and timing data submittals to be negotiated by the parties to ensure that the 

reporting of data is consistent with the type of power production forecasting being 
Docket No. RM10-11-000 - 134 -

deployed by the public utility transmission provider. The Commission revises Article 8.4 

of the pro forma LGIA accordingly.

181. In the Proposed Rule, the Commission sought to require the reporting of forced 

outages of 1 MW or more for 15 minutes or more. In response, commenters disagree as 

to the relevant level of granularity for outage data. Rather than establish a specific 

megawatt reporting threshold or frequency that could result in the reporting of data that 

are not used by the public utility transmission provider, the Commission concludes it is 

more appropriate for the public utility transmission provider and interconnection 

customer to negotiate the exact specifications of forced outage data to be provided, taking 

into account the size and configuration of the VER, its characteristics, location, and its 

importance in maintaining generation resource adequacy and transmission system 

reliability in its area. As noted in this Proposed Rule, this will provide the flexibility 

necessary to ensure that the reporting of forced outage data is commensurate with the 

power production forecasting being employed by the public utility transmission provider, 

consistent with any regional practices that may exist. Therefore, the Commission 

modifies the Proposed Rule to align the reporting of forced outages with the power 

production forecasting being employed by the public utility transmission provider. The 

Commission also declines to adopt alternative minimum thresholds or pre-define forced 

outages for purposes of reporting requirements as requested by some commenters. 

182. Some commenters request that the Commission standardize protocols for reporting 

meteorological or forced outage data required by this Final Rule. The Proposed Rule did 

not contain standard protocols for data reporting and, as a result, the merits of such a 
Docket No. RM10-11-000 - 135 -

requirement have not been fully addressed in the record. Whether standardization of data 

communications would facilitate or hinder development of power production forecasting 

may implicate a variety of data and communications issues that would benefit from broad 

industry input through standards development processes such as those used by NAESB 

and other organizations. 

d. LGIA

183. In order to effectuate the reporting requirements discussed above, the Proposed 

Rule set forth amendments to the pro forma LGIA adding a new section Article 8.4, 

Provision of Data from a Variable Energy Resource. Consistent with the approach of 

Order Nos. 2003 and 661,210 the Commission proposed not to require retroactive changes 

to LGIAs that are already in effect. However, the Commission sought comment as to 

whether this approach would prevent public utility transmission providers from 

effectively implementing power production forecasting.211 The Commission also 

preliminarily found that the pro forma LGIA includes adequate confidentiality 

protections for sensitive data obtained from VERs.212

 210 Order No. 661, FERC Stats. & Regs. ¶ 31,186 at P 120; Order No. 2003, FERC 

Stats. & Regs. ¶ 31,146 at P 910.

211 See Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 64.

212 Id. P 60 (citing Pro Forma LGIA Article 22, which sets forth the 

confidentiality provisions applicable to data exchanged through the interconnection 

process).
Docket No. RM10-11-000 - 136 -

184. The Commission noted that it was proposing revisions only to interconnection 

customers whose generating facilities are VERs greater than 20 MW and, as a result, 

proposing revisions only to the pro forma LGIA and not the pro forma Small Generator 

Interconnection Agreement (SGIA). The Commission sought comment on whether the 

proposed reforms should also apply to interconnection customers whose generating 

facilities are VERs of 20 MW or less, so as to require revisions to the pro forma SGIA.

e. Comments

185. The Commission received a variety of comments on its proposal to not require 

retroactive changes to LGIAs that are in effect. NaturEner argues that without data from 

existing resources, power production forecasts would be less reliable or robust, resulting 

in artificially high required reserves and attendant expenses. AWEA, Clean Line, and 

Iberdrola state that they would not oppose requiring data from resources that have 

executed an LGIA, provided that the interconnection customers are only required to 

report data that are currently gathered by the VER. AWEA explains that data already are 

being collected by many wind plants deployed since 2005 and that many public utility 

transmission providers have already imposed reporting requirements. However, Southern 

MN Municipal asserts that the proposed reforms should not be extended to resources that 

have already executed an interconnection agreement. Bonneville Power asserts that 

Articles 9.3 and 9.4 of the LGIA give the transmission provider a unilateral right to 

update its instructions and operating protocols and procedures regardless of whether the 

proposed Article 8.4 is applied retroactively. 
Docket No. RM10-11-000 - 137 -

186. Midwest ISO Transmission Owners request that the Commission address the 

circumstances under which a VER with an existing interconnection agreement might 

become subject to the new power production forecasting requirement if it is applied 

prospectively. Midwest ISO Transmission Owners state that, at the very least, any 

increase in a facility’s generating capacity or material modification that would necessitate 

a new LGIA should be sufficient to subject the VER generator to the new power 

production forecasting-related data requirements under the applicable tariff.

187. Some commenters suggest implementing reporting requirements for 

meteorological and forced outage data through the pro forma OATT in order to impose 

those requirements on existing resources or otherwise allow for changes in reporting 

requirements over time.213 AWEA contends that, if the Commission determines to apply 

the reporting requirements to existing resources, it would be more appropriate to place 

the requirements in the pro forma OATT. Sunflower and Mid-Kansas agree, noting that 

the pro forma LGIA already requires parties to operate their facilities consistent with 

Applicable Laws and Regulations, including OATT requirements. Large Public Power 

argues that it is important that all VERs provide the operational information required by a 

transmission provider and, therefore, also recommends placing reporting requirements in 

the transmission tariff. Southern California Edison contends that placing reporting 

requirements in the pro forma OATT would allow greater flexibility in structuring 

 213 E.g., AWEA; Large Public Power; Southern California Edison; Sunflower and 

Mid-Kansas.
Docket No. RM10-11-000 - 138 -

agreements by referencing requirements in the California ISO Tariff, as they may change 

from time to time.

188. Other commenters ask the Commission to allow reporting requirements to be 

stated in market rules or business practices.214 ISO New England requests that the 

Commission afford flexibility for public utility transmission providers to determine the 

mechanism by which to collect the required VER data. National Grid states that rather 

than requiring a proscriptive amendment of the pro forma LGIA, the Commission should 

require each region to work with its stakeholders to develop appropriate methods for 

forecasting the energy output from VERs. Pacific Gas & Electric requests that in its 

Final Rule the Commission provide latitude for the California ISO and other similarlysituated transmission providers to continue their existing programs for gathering relevant 

meteorological and operational data, and proposing incremental refinements to them, so 

long as they conform to the purposes of the Final Rule. Xcel similarly argues that the 

specific data requirements for individual public utility transmission providers should be 

identified through a business practice or other OASIS posting to allow adjustments due to 

changing system operating needs, improvements in meteorological forecasting 

technologies, or modifications in NERC reliability requirements. 

189. With regard to the Commission’s question as to whether the pro forma SGIA 

needs to be revised, many parties argue that the provision of data under the SGIA may be 

 214 E.g., California PUC; Dominion; ISO New England; National Grid; Pacific Gas 

& Electric.
Docket No. RM10-11-000 - 139 -

appropriate in some instances.215 PJM and Snohomish County PUD note that the costs of 

reporting the proposed data to public utility transmission providers by small VERs could 

be higher than for larger resources. As such, they argue that the Commission should 

carefully consider these costs when applying reporting requirements. Several other 

commenters acknowledge difficulties associated with gathering data from resources 

subject to the SGIA, and propose a variety of thresholds to determine whether reporting 

requirements should apply to the resource.216 For example, AWEA states that it makes 

sense to apply similar data reporting requirements to smaller-scale generators where it 

can be demonstrated that the data will be used for improving VER forecast accuracy and 

that the benefits exceed the cost of data collection. Others state that small resources 

should use alternative reporting requirements.217 Southern California Edison 

recommends that the Commission consider an approach that aggregates individual site 

data from small generators in a geographic area, which reduces cost impacts to smaller 

projects.

 215 E.g., California ISO; EEI; Duke; ISO New England; MidAmerican; NRECA; 

Pacific Gas & Electric; PNW Parties; Snohomish County PUD; Southern California 

Edison; Tacoma Power; Xcel.

216 E.g., AWEA; RenewElec; SEIA; Tacoma Power; Xcel.

217 E.g., Alstom Grid; RENEW.
Docket No. RM10-11-000 - 140 -

190. Commenters contend that the public utility transmission provider should have the 

flexibility to identify and require data from small generators.218 For example, Bonneville 

Power argues that the Commission should require small VERs to provide meteorological 

and operational data according to the requirements established by their public utility 

transmission provider. These commenters generally agree that public utility transmission 

providers may have different forecasting needs, and that they require flexibility to 

address such issues. NextEra argues that there is no convincing reason to limit the 

forecasting requirement to resources larger than 20 MW, and that the impact of small 

VERs on system variability is the same as resources greater than 20 MW. Midwest ISO 

Transmission Owners note that the Midwest ISO pro forma Generator Interconnection 

Agreement (GIA) applies to all interconnection customers, regardless of size, and as a 

result any reporting requirements adopted in the GIA should apply to generators with a 

capacity of less than 20 MW. California PUC asks that the Commission make clear that 

public utility transmission providers are not prohibited from requesting meteorological 

and operational data from small VERs. Environmental Defense Fund states that the 

Commission should host a technical conference to examine issues arising from requiring 

small generators to contribute information to support power production forecasting.

191. Some commenters address other aspects of the Commission’s proposal to amend 

the pro forma LGIA. AWEA questions the Commission’s preliminary conclusion that 

 218 E.g., Bonneville Power; Idaho Power.
Docket No. RM10-11-000 - 141 -

the LGIA provides sufficient confidentiality protection for sensitive operational and 

meteorological data, stating that vendors providing forecasts to public utility transmission 

providers must not be allowed to use the data they collect for developing forecasts for the 

public utility transmission provider for any other purpose without express agreement. 

MidAmerican asks the Commission to clarify that there will not be any additional 

penalties for failure to provide accurate meteorological and operational data, other than 

the contractual remedies for breach already provided for in the pro forma LGIA. 

MidAmerican states that it recognizes that meteorological data are not always available 

if, for example, communication from a collecting device is interrupted. RenewElec 

recommends that the Commission set forth a data retention requirement in the new pro 

forma LGIA Article 8.4 that would require public utility transmission providers to 

maintain data collected from interconnection customers whose generating facilities are 

VERs for at least 10 years, facilitating follow-up studies to update power production 

forecasts. 

f. Commission Determination

192. The Commission affirms the Proposed Rule and amends the pro forma LGIA to 

include a new Article 8.4 setting forth the reporting requirements adopted in this Final 

Rule. The Commission directs all public utility transmission providers to file a revised 

pro forma LGIA within 12 months of the effective date of this Final Rule reflecting the 

revisions adopted herein. As noted below, public utility transmission providers that have 

already implemented meteorological or forced outage reporting requirements may seek to 
Docket No. RM10-11-000 - 142 -

demonstrate, on compliance, that these existing business practices and market rules 

adequately satisfy the requirements of this Final Rule. 

193. As set forth in the Proposed Rule, Article 8.4 of the pro forma LGIA did not state 

where the meteorological and forced outage data reporting requirements would be 

specified in an LGIA. The Commission agrees with Bonneville Power that it is 

appropriate to state reporting requirements for meteorological and forced outage data in 

Appendix C, Interconnection Details, as this will allow the requirements to be changed 

from time to time. The Commission therefore revises proposed Article 8.4 to specify that 

reporting requirements for meteorological and forced outage data would be set forth in 

Appendix C, Interconnection Details, of an LGIA. A transmission provider with an 

executed LGIA that seeks reporting of such data may negotiate revisions to Appendix C 

related to such reporting requirements with the interconnection customer. To the extent 

the parties mutually agree on changes to Appendix C, such changes to Appendix C need 

not be submitted to the Commission for review. If the parties are unable to reach 

agreement on proposed modifications to Appendix C, however, these parties may invoke 

their rights, as relevant, to modify the LGIA under sections 205 or 206 of the FPA, as 

appropriate, and pursuant to Article 30.11 of the LGIA. 

194. The Commission disagrees with commenters suggesting that flexibility provided 

by business practices or market rules makes them a superior alternative for implementing 

the meteorological and forced outage reporting requirements adopted in this Final Rule. 

The Commission has sought to address public utility transmission providers’ need for 

flexibility by clarifying that reporting requirements are to be set forth in Appendix C to 
Docket No. RM10-11-000 - 143 -

the LGIA, while also addressing interconnection customers’ need for certainty in the 

obligations placed on them. The Commission appreciates that public utility transmission 

providers in some regions, including RTOs and ISOs, have already implemented 

meteorological or forced outage reporting under business practices and markets rules. 

Such public utility transmission providers may seek to demonstrate in their compliance 

filing how continued use of these existing business practices and market rules is adequate 

to satisfy the requirements of this Final Rule using the independent entity variation 

standard set forth in Order No. 2003, if relevant, or by demonstrating variations from the 

pro forma OATT are consistent with or superior to the requirements of this Final Rule.219 

195. The Commission declines to modify existing LGIAs already in effect to include 

Article 8.4 of the pro forma LGIA as adopted in this Final Rule. The Commission 

acknowledges that, in some situations, there may be a sufficient amount of VERs already 

interconnected to the public utility transmission provider’s system to make data from 

those resources useful or even necessary to properly implement power production 

forecasting. However, several considerations lead us to decline to modify every LGIA in 

effect on a generic basis. First the Commission believes retroactive changes to every 

LGIA in effect could be administratively burdensome to public utility transmission 

providers and interconnection customers, especially where the public utility transmission 

provider is not engaged in power production forecasting. Second, we note that nothing in 

 219 Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at PP 9-10.
Docket No. RM10-11-000 - 144 -

the pro forma LGIA precludes the parties to an LGIA from mutually agreeing to revise 

the requirements set forth in Appendix C to reflect the reporting of meteorological and 

forced outage data. Indeed, we note that Article 9.4 of the pro forma LGIA recognizes 

that Appendix C will be modified to reflect changes to the interconnection customer’s 

requirements as they may change from time to time. Finally, if the parties are unable to 

agree to modifications of Appendix C, we note that pursuant to Article 30.11 of the pro 

forma LGIA, the transmission provider has the right to make a unilateral filing to the 

Commission proposing to modify an existing LGIA under section 205of the FPA. 

196. For similar reasons, the Commission declines suggestions to implement data 

reporting requirements through the pro forma OATT instead of the pro forma LGIA or to 

include the requirements in the pro forma SGIA. The effect of relying on the pro forma 

OATT would be to impose the data reporting requirements adopted in this Final Rule on 

existing interconnection customers retroactively, including those with resources under 20 

MW that are subject to the pro forma SGIA. Like data from existing resources, data from 

small resources may be useful or necessary for power production forecasting, yet the 

record in this proceeding does not demonstrate that the need for data from small 

resources is so great as to outweigh the potential burden that reporting requirements 

could impose on smaller resources. Just as the pro forma LGIA provides an opportunity 

for public utility transmission providers to mutually agree with interconnection customers 

regarding reporting requirements, nothing in the pro forma SGIA precludes the 

transmission provider from negotiating with the owners and operators of small VERs to 

update their SGIAs to provide for the reporting of meteorological and forced outage data 
Docket No. RM10-11-000 - 145 -

that are necessary for public utility transmission providers to employ power production 

forecasting. As with the pro forma LGIA, section 12.12 of the pro forma SGIA provides 

an opportunity for parties to an SGIA to bring any disagreement to the Commission for 

resolution.

197. In response to Midwest ISO Transmission Owners, the Commission notes that the 

extent to which a new LGIA is necessitated by a new Interconnection Request or Material 

Modification is governed by the pro forma LGIA and Commission precedent. To the 

extent a new LGIA is warranted, the VER interconnection customer would be subject to 

the relevant requirements of this Final Rule in effect at the time. Public utility 

transmission providers may seek to demonstrate in their compliance filings how 

continued use of existing tariffs, business practices and/or market rules is adequate to 

satisfy the requirements of this Final Rule using the independent entity variation standard 

set forth in Order No. 2003, if relevant, or by demonstrating variations from the pro 

forma OATT are consistent with or superior to the requirements of this Final Rule.220 

198. With regard to AWEA’s concern regarding the confidentiality of data, the 

Commission agrees that meteorological and forced outage data can be commercially 

sensitive, but concludes that the Article 22 of the pro forma LGIA provides adequate 

safeguards for reported data.221 Any vendor providing forecasts to a public utility 

 220 See Id. P 910.

221 Article 22 of the pro forma LGIA defines Confidential Information to include, 

among other things, all information relating to a Party’s technology, research and 

 

(continued...)
Docket No. RM10-11-000 - 146 -

transmission provider would be an agent of the public utility transmission provider 

subject to the confidentiality obligations of the pro forma LGIA. With regard to 

MidAmerican’s concern regarding penalties for failure to provide accurate 

meteorological and forced outage data, the Commission notes that the extent to which 

penalties beyond those set forth in the pro forma LGIA might be appropriate for failing to 

satisfy data reporting requirements will necessarily depend on the facts and 

circumstances surrounding each instance of failed reporting. The Commission 

appreciates that unforeseen circumstances may impair an interconnection customer’s 

ability to report data and that the impact of failed reporting may in many instances be de 

minimus. However, it would not be appropriate for the Commission to conclude 

generically that in no circumstance would additional penalties beyond those remedies set 

forth in the pro forma LGIA be appropriate for failure to comply with the data reporting 

requirements of an executed LGIA. 

199. Finally, the Commission declines to impose special retention requirements for 

reported meteorological and forced outage data as requested by RenewElec. The time 

period over which a public utility transmission provider would need to retain 

meteorological or forced outage data will be a function of the type of power production 

forecasting being employed by the public utility transmission provider. 

 

development, business affairs, and pricing. Each party to an LGIA must hold in 

confidence and may not disclose to any person Confidential Information during the term 

of an LGIA and for a period of three years after the expiration or termination of an LGIA. 
Docket No. RM10-11-000 - 147 -

2. Definition of VER

a. Commission Proposal

200. In the Proposed Rule, the Commission sought to modify the pro forma LGIA to 

include a new definition for Variable Energy Resource in Article 1. The proposed 

definition identified a Variable Energy Resource as a device for the production of 

electricity that is characterized by an energy source that: (1) is renewable; (2) cannot be 

stored by the facility owner or operator; and (3) has variability that is beyond the control 

of the facility owner or operator.222 The Commission stated that it believed the proposed 

definition was consistent with NERC’s characterization of variable generation.223

b. Comments

201. EEI supports the Commission’s proposed definition without modification. 

California ISO supports the definition’s focus on source of energy, but suggests that the 

phrase “by an energy source that” be replaced with “by a fuel source that.” California 

ISO states that this change would make clear that the three conditions that follow pertain 

to the fuel source and not the nature of the facility itself. 

202. Other commenters disagree with the focus on the source of energy, arguing that a 

VER should be defined by reference to its operating characteristics, including the ability 

 222 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 64.

223 Id. (citing NERC, Accommodating High Levels of Variable Generation 13-14 

(2009), available at http://www.nerc.com/files/IVGTF_Report_041609.pdf). 
Docket No. RM10-11-000 - 148 -

to control output.224 BrightSource states that this would allow for comparison between 

facilities with different fuel sources on standard operational and reliability time-frames 

and also avoid confusion about types of plants that combine renewable and conventional 

fuel sources, such as solar-gas hybrids. Joined by SEIA, BrightSource argues that a plant 

able to maintain a high level of operational control comes close to fulfilling the 

operational characteristics of a non-VER generation and should be treated as such for 

purposes of the Proposed Rule’s requirements. NextEra agrees, stating that some 

resources can control the variability of their facility by adjusting output through 

feathering blades, self-curtailment, or similar measures. SEIA suggests that the 

Commission consider alternative criteria that could provide a distinction between VERs 

with a high level of control and VERs without such controls, such as if actual production 

can remain within some statistical measure of forecast accuracy during its operating 

hours. MidAmerican similarly requests that the Commission adopt a definition based on 

physical electrical generation output characteristics rather than input attributes such as 

fuel type, suggesting that whether energy sources qualify as “renewable” varies among 

states that have developed their own renewable resource regulations. 

203. Several of these commenters question the applicability of the proposed definition 

to resources that use energy storage to control output. NaturEner provides a hypothetical 

example of a plant coupled with storage and asks that the Commission provide 

 224 E.g., AWEA; BrightSource; NaturEner; NextEra; RenewElec; SEIA.
Docket No. RM10-11-000 - 149 -

clarification regarding the impact of such pairing on capacity reserve obligations. 

BrightSource asks the Commission to modify the definition to address how much storage 

results in a plant not being considered a VER for purposes of the Proposed Rule and any 

future rules. AWEA and NextEra request clarification that the proposed definition would 

not prevent VERs from electing to maintain VER status even if they use energy storage, 

other firming technologies, or otherwise have the ability to adjust output. RenewElec and 

SEIA argue that, regardless of the Commission’s determination on the storage issue for 

VERs, such resources should not be exempt from reporting meteorological data to their 

public utility transmission provider. BrightSource and SEIA state that the applicability of 

the proposed definition is sufficiently important that the Commission should consider a 

technical conference on the issue.

204. Some commenters focus on the applicability of the proposed definition to 

particular types of resources, such as tidal, run-of-river hydro, conduit hydro, cogeneration, or biomass.225 Snohomish County PUD argues that, although such facilities 

would appear to satisfy the proposed definition, they should not be required to report the 

proposed data to public utility transmission providers because the data reporting would 

provide minimal benefit to grid operators while imposing a significant burden on these 

resources. Focusing on run-of-river hydro, Snohomish County PUD contends that 

whether such a facility is available at any given moment has no impact on the extent to 

 225 E.g., Grays Harbor PUD; NorthWestern; Pacific Gas & Electric; Snohomish 

County PUD. 
Docket No. RM10-11-000 - 150 -

which a sudden wind ramp might change production on the grid. NorthWestern and 

Pacific Gas & Electric agree, arguing that run-of-river hydro is much more predictable 

than wind or solar generation on a short-term basis and, as a result, there would be little 

benefit to collecting the meteorological data from such resources. In contrast, Entergy 

argues that the proposed definition and associated reporting requirements should be 

imposed on Qualifying Facilities to avoid gaps in forecasting and to allow public utility 

transmission providers to accommodate the variability that exists with both Qualifying 

Facilities and VERs.

205. Other commenters question the application of the proposed definition to solar 

resources.226 California ISO explains that while solar thermal resources store solar 

thermal heat, they do not store solar irradiance itself, which is the energy source for the 

solar thermal facility. California ISO asks the Commission to clarify that a solar thermal 

facility would fall under the proposed definition. BrightSource contends that the storage 

and variability elements of the proposed definition appear to overlap functionally for a 

solar thermal plant, given that variability during the operating day could be controlled in 

many ways by the facility. BrightSource requests clarification regarding whether a VER 

would have to meet both or just one of these elements to fall within the definition. 

206. ISO New England and NorthWestern offer opposing views on application of the 

proposed definition and associated reporting requirements on behind-the-meter 

 226 E.g., BrightSource; California ISO.
Docket No. RM10-11-000 - 151 -

generation. ISO New England recommends that all distributed or behind-the-meter 

generation should be required to provide to the balancing and transmission entities in its 

area, at a minimum, specification of the technology and precise location of the installed 

resource so that a forecast of output can be developed on an aggregate scale to include in 

the balancing area forecast. 

207. California State Water Project argues that its wholesale participating load resource 

also meets the definition of a VER. California State Water Project explains that 

participating load’s primary purpose is not the provision of services to the grid, but rather 

water management, and that the load is subject to variability for reasons beyond 

California State Water Projects’ control, such as competing environmental and water 

management requirements. Accordingly, California State Water Project requests that 

consideration be given to expanding the VERs definition to include large wholesale 

demand response resources that bid into markets not through a baseline mechanism, but 

rather on a basis comparable to generation.

208. ISO New England requests that the Commission afford flexibility for entities to 

use existing, superior definitions of VERs. The ISO New England Tariff already uses the 

term “Intermittent Power Resources” for wind, solar, run-of-river hydro and other 

renewable resources that do not have control over their net power output. As such, ISO 

New England requests that the Commission allow entities to use existing, superior 

approaches to the extent these are consistent with the objectives of the proposed reforms. 

ISO New England states that adding another term to its tariff could potentially lead to 

confusion, and therefore, argues that the region should be afforded the opportunity to 
Docket No. RM10-11-000 - 152 -

consider the existing terminology in the ISO New England Tariff, and determine whether 

any changes are warranted. 

209. Bonneville Power states that, in light of its position that the pro forma LGIA 

provides transmission providers with the authority to update operational requirements for 

VERs, the Commission’s proposed definition is unnecessary. However, Bonneville 

Power nonetheless states that it supports the inclusion of the proposed definition in all 

new VER interconnection agreements. 

c. Commission Determination

210. The Commission adopts the Proposed Rule’s definition of VER and, accordingly, 

amends Article 1 of the pro forma LGIA to include the following definition: 

Variable Energy Resource shall mean 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.

 

The Commission finds it necessary to define VERs in the pro forma LGIA in order to 

identify those resources that are required to provide to their public utility transmission 

provider meteorological and forced outage data necessary to enable the public utility 

transmission provider to develop and deploy power production forecasting. The 

Commission therefore declines to define VERs by their operating characteristics as 

suggested by BrightSource and MidAmerican or by reference to their lack of ability to 

store output, self-curtail production, or otherwise firm deliveries as suggested by 

BrightSource, NextEra and others. The Commission also declines to define VERs by 
Docket No. RM10-11-000 - 153 -

their fuel type as suggested by California ISO, because fuel type is an unduly restrictive 

subset of energy type.227

211. As noted elsewhere in this Final Rule, power production forecasting allows the 

public utility transmission provider to understand the characteristics of the input energy 

source for particular resources, to use those characteristics to predict how the resources 

will operate, and in turn to determine whether and to what degree the public utility 

transmission provider will need to reserve capacity to manage variability in generation 

output. Therefore, it is the variability of the energy source, not the operating 

characteristics of the plant or nature of output, that are critical to identifying the set of 

resources that must be subject to the meteorological and forced outage data requirements 

adopted above. Defining VERs by reference to operating characteristics or level of storage 

could limit the reporting of data in ways that undermines that ability of public utility 

transmission providers to engage in power production forecasting.

212. The Commission declines to establish an exemption to the data reporting 

requirements in this Final Rule for VERs utilizing energy storage or other firming 

technologies. Not only would this exemption inhibit the public utility transmission 

provider’s capacity to predict how the VER resources will operate, but there is also 

insufficient evidence in this record to identify an objective threshold for exemption. The 

Commission clarifies that the purpose of this definition is to identify the resources that 

 227 “Fuel” is defined as a material used to produce heat or power by burning. See 

Merriam Webster, http://www.Merriam-Webster.com, 2011. (November 4, 2011). 
Docket No. RM10-11-000 - 154 -

are required by this Final Rule to provide to their public utility transmission provider 

meteorological and forced outage data; the purpose is not, as suggested by NaturEner, to 

assign capacity reserve obligations or other charges. Nor does this definition supersede 

those created by other entities for purposes outside this rule, such as tax benefit purposes 

or renewable energy credits.

213. For similar reasons, the Commission declines to limit the VER definition in the 

pro forma LGIA to solar and wind resources so as to exclude run-of-river hydro, tidal, or 

other new and emerging VER technologies. Although the Commission anticipates that 

public utility transmission providers initially will engage in power production forecasting 

predominantly for wind and solar VERs, we leave to the public utility transmission 

providers to determine whether their individual systems necessitate power production 

forecasting for other types of VERs. Categorically excluding other types of resources

would undermine the flexibility being provided in this Final Rule. At the same time, we 

decline to establish minimum reporting requirements for non-wind and non-solar VERs 

and leave to the public utility transmission providers and VERs to negotiate what data are 

necessary for developing and deploying power production forecasting for these resources, 

taking into account the size and configuration of the VER, its characteristics, location, 

and its importance in maintaining generation resource adequacy and transmission system 
Docket No. RM10-11-000 - 155 -

reliability in its area.

228 Because such requirements will vary system by system, it is not 

necessary to hold a technical conference to explore generic application of the VER 

definition as suggested by BrightSource and SEIA. 

214. In response to California State Water Project, the Commission clarifies that VERs 

are not defined herein to include demand response resources. A demand response 

resource is not a device for the production of electricity and, therefore, would not fall 

within the VER definition adopted in the pro forma LGIA.229 In response to ISO New 

England and NorthWestern, the definition potentially could apply to behind-the-meter 

generation, although such resources would only be subject to data reporting requirements 

adopted in this Final Rule to the extent they enter into a new LGIA or materially modify 

an existing LGIA after the effective date of this Final Rule. 

215. ISO New England inquires as to the impact of the VER definition on other 

definitions in a public utility transmission provider’s existing tariff. As noted above, 

public utility transmission providers that are RTOs or ISOs may seek to demonstrate in 

their compliance filing how existing tariffs, business practices or market rules are 

adequate to satisfy the requirements of this Final Rule using the independent entity 

 228 If parties are unable to reach an agreement the public utility transmission 

provider may submit a filing requesting the data and demonstrating how it will be used 

for power production forecasting pursuant to section 205 of the FPA. 

229 A demand response resource may use behind-the-meter generation, potentially 

including VERs, to facilitate the provision of demand response. Such use, however, does 

not mean that such behind-the-meter generation is itself a demand response resource.
Docket No. RM10-11-000 - 156 -

variation standard set forth in Order No. 2003, if relevant, or by demonstrating variations 

from the pro forma OATT are consistent with or superior to the requirements of this 

Final Rule. 

216. With regard to Entergy’s request that the Commission apply the proposed outage 

reporting requirement to Qualifying Facilities, we clarify that the data-reporting 

requirements under this rule apply to interconnection customers whose generating 

facilities are VERs as defined herein. Specifically, when an electric utility purchases an 

interconnected Qualifying Facility’s total output, the relevant state authority exercises 

authority over the interconnection and the allocation of interconnection costs. But when 

an electric utility interconnecting with a Qualifying Facility does not purchase all of the 

Qualifying Facility’s output and instead transmits the Qualifying Facility power in 

interstate commerce to another purchaser, the Commission exercises jurisdiction over the 

rates, terms, and conditions affecting or related to such service, such as 

interconnections.230 Thus, for a Qualifying Facility that is a VER, when the 

interconnected Qualifying Facility is selling its total output to an electric utility, the 

meteorological and forced outage reporting requirements of this Final Rule do not apply.

However, when an electric utility interconnecting with a Qualifying Facility does not 

 230 Order No. 2003, FERC Stats. & Regs. ¶ 61,103 at P 813. The Commission 

regulations governing the exemptions enjoyed by Qualifying Facilities are codified at 

18 C.F.R. Part 292, Subpart F (18 C.F.R. §§ 292.601-.602 (2011)). Limited exemptions 

from sections 205 and 206 of the FPA apply to certain sales of energy and capacity made 

by Qualifying Facilities. See also Terra-Gen Dixie Valley, LLC, 132 FERC ¶ 61,215, at 

PP 45-46 (2010).
Docket No. RM10-11-000 - 157 -

purchase all of the Qualifying Facility’s output and instead transmits the Qualifying 

Facility power in interstate commerce to another purchaser, the meteorological and 

forced outage reporting requirements of this Final Rule are applicable.

3. Data Sharing

a. Commission Proposal

217. In the Proposed Rule, the Commission sought comment on whether public utility 

transmission providers should be allowed or required to share VER-related data received 

from interconnection customers with other entities, like the source or sink balancing 

authority area for a transaction, or a government agency, such as NOAA, assuming 

confidentiality is protected.231

b. Comments 

218. Clean Line and RenewElec state that operational and meteorological data should 

be made public to the maximum extent possible. RenewElec argues that there is a 

significant lack of operational data available to researchers in the area of VERs 

integration, and asks that the Commission require that: (1) VER data be made public 

within six months of the date on which such data is submitted by the interconnection 

customer, and (2) operational data, including VER data, used by transmission providers 

to develop VER power production forecasting be made available to interested parties. 

 231 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 63.
Docket No. RM10-11-000 - 158 -

219. While generally stating support for the sharing of data, some commenters raise 

confidentiality concerns and point out the commercially-sensitive nature of data subject 

to the reporting requirements contemplated in the Proposed Rule.232 For example, 

Southern California Edison supports sharing VER-related data for the purposes of 

increasing forecasting accuracy, as long as the data are not proprietary data that the 

public utility transmission provider is prohibited from disclosing to other parties. 

Bonneville Power and a few others contend that while sharing data from individual VERs 

poses confidentially issues, sharing aggregate VER data does not pose the same 

problems.233 Sunflower and Mid-Kansas state that, within RTOs, the stakeholders should 

decide which entities should be provided VER data. Western Farmers request that the 

Commission confirm that, where the transmission provider is not the balancing authority, 

the data should also be provided to the relevant balancing authority. NextEra and AWEA 

only support sharing data with other balancing authorities when the resource is being 

dynamically scheduled or dispatched into that balancing authority. Bonneville Power 

suggests that, at a minimum, the Commission should allow public utility transmission 

providers and balancing authorities to share aggregate forecasts for VER output with all 

parties to an e-tag. 

 232 E.g., CGC; California PUC; EEI; NextEra; PJM; SMUD; ISO New England.

233 E.g., Bonneville Power; California ISO; Exelon; SEIA.
Docket No. RM10-11-000 - 159 -

220. Several commenters support sharing VER-related meteorological data with 

NOAA, including having the data incorporated into foundational models run by 

NOAA.234 Commenters, including NOAA, request that the Commission require VERs to 

submit meteorological data to NOAA for the purpose of improving atmospheric 

characterization and forecast accuracy.235 In response to confidentiality concerns, NOAA 

states that private sector proprietary data can be protected from distribution and 

anonymized in the analysis and generation of forecasts, which would then allow 

improved predictions to be available for the private sector to incorporate into power 

production forecasts.

c. Commission Determination

221. The Commission declines to expand the Proposed Rule to require public utility 

transmission providers to share VER related data with other entities such as a balancing 

authority area or NOAA. However, the Commission strongly encourages the voluntary 

sharing of data where appropriate. Many commenters assert that significant benefits 

might flow from VERs sharing data with entities such as a balancing authority area or 

NOAA. The Commission finds that VERs are in the best position to negotiate what data 

are needed and to weigh the benefits that may be expected as a result of providing such 

data. In addition, negotiating directly with other entities will allow VERs to ensure that 

 234 E.g., AWEA; Bonneville Power; CGC; Iberdrola; ISO New England; 

MidAmerican; NaturEner; NOAA.

235 E.g., Bonneville Power; Iberdrola; NOAA.
Docket No. RM10-11-000 - 160 -

adequate confidentiality protections are in place for information that they may consider to 

be commercially sensitive or otherwise confidential. If helpful to industry participants, 

the Commission will consider making staff available to work through issues and, if 

appropriate, take additional steps to facilitate the voluntary sharing of information.

4. Cost Recovery

a. Commission Proposal

222. In the Proposed Rule, the Commission refrained from proposing a single method 

of cost recovery for the development and implementation of power production forecasts. 

Instead, the Commission sought comments on how public utility transmission providers 

may recover costs incurred to develop and deploy power production forecasting tools.236

b. Comments

223. Among those seeking flexibility, AWEA states that the Commission is correct to 

not propose a single uniform method for allocating these costs, and instead should defer 

to public utility transmission providers and others to determine how these costs should be 

allocated. Several commenters request that the Final Rule provide flexibility to public 

utility transmission providers and/or regions to propose cost recovery approaches.237 For 

example, EEI contends that generally no interconnected resource should be exempt from 

the responsibility for costs that it causes to be incurred, but asks that the Commission not 

 236 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 57.

237 E.g., AWEA; California PUC; Duke; ISO New England; MidAmerican; Pacific 

Gas & Electric. 
Docket No. RM10-11-000 - 161 -

mandate how costs should be allocated at this time, allowing regions to develop 

appropriate cost-recovery solutions. 

224. Some commenters recommend that the cost of forecasting be spread among all 

transmission customers.238 Independent Power Producers Coalition-West argues that 

forecasting tools will ultimately reduce costs to utilities and generators, and will 

ultimately be a small cost of doing business in a world where forecasting can and should 

be a constant element of the power scheduling process. Public Interest Organizations 

state that the costs of centralized forecasting infrastructure should be spread across all 

those who benefit from the improved accuracy and decreased costs, provided those costs 

are demonstrated to be just and reasonable. Joined by NextEra, Public Interest 

Organizations argue that the broad benefits of forecasting justify the sharing of related 

costs across the transmission system(s) that benefit. 

225. Iberdrola contends that there is no difference in the costs incurred to develop and 

deploy power production forecasting tools and the costs of developing and implementing 

other market design features. Iberdrola states that these types of costs typically are not 

directly assigned to one set of market participants, but are spread to all users of the 

transmission system because they benefit all users of the system. Iberdrola states that the 

costs incurred to develop and deploy power production forecasting tools should similarly 

be spread to all system users.

 238 E.g., Iberdrola; Independent Power Producers Coalition-West; NextEra; Public 

Interest Organizations; Exelon.
Docket No. RM10-11-000 - 162 -

226. Exelon recommends recovering the cost of forecasting within administrative 

charges, the approach taken by PJM and ERCOT. Exelon provides an example of 

ERCOT’s handling of the costs: the cost of developing the ramp probability tool was a 

one-time investment that was recovered by the transmission provider in uplift to the 

market. The ongoing cost of using the tool is also spread across the market. Exelon 

states that this approach avoids the problem of free-ridership by future market 

participants that would occur if these costs were recovered solely from existing market 

participants.

227. Other commenters argue either that the VERs, or the beneficiaries of VERs, 

should be financially responsible for the costs of forecasting.239 These commenters 

generally contend that public utility transmission providers should be able to recover the 

costs incurred to develop and deploy power production forecasting by imposing a fee or 

rate upon the VERs causing the costs to be incurred. For example, NRECA argues that 

non-VER transmission customers are neither causing nor benefiting from the 

enhancements to power production forecasting and, therefore, should not be forced to 

subsidize its costs, citing Northern States Power Company.

240 Montana PSC suggests 

that all VERs of 1 MW or greater should be responsible for power production forecasting 

 239 E.g., Bonneville Power; ELCON; Large Public Power Counci; MidAmerican; 

Midwest ISO Transmission Owners; Montana PSC; NorthWestern; NRECA; Oregon & 

New Mexico PUC; PNW Parties; SMUD; Southern California Edison; Tacoma Power. 

240 NRECA (citing N. States Power Co., 64 FERC ¶ 61,324, at P 63,379 (1993)).
Docket No. RM10-11-000 - 163 -

costs. Pacific Gas & Electric notes the approach taken in the California ISO’s 

Participating Intermittent Resources Program, in which the California ISO charges a fee 

to VERs to recover costs to develop and deploy power production forecasts.

228. ELCON and Tacoma Power argue that any resource, whether or not it is a VER, 

should be held fully accountable for the costs it causes the transmission provider to incur 

on its behalf. ELCON argues that meteorological forecasting is simply a cost of doing 

business for wind energy, just as a nuclear power plant must pay for storage of spent fuel. 

ELCON argues that these costs should not be recovered in uplift charges in regions 

served by ISOs or RTOs, or allocated to non-customers of VER transactions. 

229. SEIA recommends that the Commission examine whether there may be market 

entities that would consider contributing to the costs of the forecast service providers in 

the non-organized market regions, e.g., power traders may be willing to pay for the 

aggregate day-ahead and hour-ahead forecasts across such regions. SEIA states that 

these revenues could be used to develop aggregated forecasts for more geographical areas 

within a region that could further reduce integration costs.

230. Duke argues that the Commission should allow public utility transmission 

providers to update any costs associated with the Proposed Rule’s reporting and power 

production forecasting requirements without triggering a general rate case. Duke 

suggests that one possible option would be through a formula rate that is updated 

periodically for changes in costs related to forecasting and data reporting. 
Docket No. RM10-11-000 - 164 -

231. Finally, some commenters request that the Commission recognize that the costs of 

centralized forecasting go beyond the expense of forecasting tools.241 These additional 

costs include gathering data, installing and operating onsite telemetry, equipment to 

record meteorological data, and data management. Southern California Edison points out 

that data and telemetry are only as good as the personnel assessing the information. 

c. Commission Determination

232. The Commission finds that it is not necessary to prescribe a single method of cost 

recovery for developing and implementing power production forecasting, as it is likely 

that not all public utility transmission providers will develop power production 

forecasting, given regional differences in the types and penetration of VERs. Moreover, 

the record in this proceeding demonstrates that the circumstances under which a public 

utility transmission provider may decide to develop and deploy power production 

forecasting may vary by system. In some instances, public utility transmission providers 

might develop and employ power production forecasting in order to manage more 

effectively the commitment of reserves associated with the provision of generator 

regulation service, as discussed in other sections of this Final Rule. In other 

circumstances, public utility transmission providers might develop and employ power 

production forecasting to manage reserve costs recovered under other ancillary services. 

In addition, public utility transmission providers may seek to recover costs associated 

 241 E.g., Pacific Gas & Electric; Southern California Edison; NorthWestern.
Docket No. RM10-11-000 - 165 -

with power production forecasting in different ways, as cost recovery may be sought via 

a general rate case, formula rate, or other mechanism. Given the myriad of factors that 

may be relevant to the allocation and recovery of such costs, the Commission finds it 

appropriate to evaluate requests for the recovery of costs incurred to develop and deploy 

power production forecasts on a case-by-case basis consistent with FPA section 205 and 

Commission precedent.

C. Generator Regulation Service-Capacity

233. In the Proposed Rule, the Commission preliminarily found that clarifying the 

manner by which public utility transmission providers may recover the costs associated 

with fulfilling their obligation to offer generator regulation service would remove barriers 

to the integration of VERs by eliminating public utility transmission providers’ 

uncertainty regarding cost recovery.242 As discussed below, the Commission concludes 

that adoption of this reform could inhibit the flexibility to design capacity services that 

align with the operational practices or needs of a particular public utility transmission 

provider. The Commission therefore declines to adopt a generic Schedule 10 for 

generation regulation service this reform and instead provides guidance to assist public 

utility transmission providers and their customers in the development and evaluation of 

proposals related to recovering the costs of regulation reserves associated with VER 

integration.

 242 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 87.
Docket No. RM10-11-000 - 166 -

1. Schedule 10-Generator Regulation and Frequency Response

Service

234. In the Proposed Rule, the Commission proposed incorporating into the pro forma 

OATT a new ancillary service schedule for Generator Regulation and Frequency 

Response Service. The Commission introduced this proposal with a review of the 

adoption in Order Nos. 888243 and 890244 of ancillary services schedules for Regulation 

and Frequency Response Service (regulation service), energy imbalance service, and 

generator imbalance service.245 The Commission repeats that introduction here for 

background.

235. Regulation service, offered under Schedule 3 of the pro forma OATT, provides the 

capacity reserve necessary for the continuous balancing of resources (generation and 

interchange) with load to maintain a scheduled interconnection frequency of 60 cycles 

per second (60 Hz).246 In Order No. 888, the Commission required public utility 

transmission providers to offer regulation service for transmission service within or into 

the public utility transmission provider’s balancing authority area to serve load in that 

area.

247 However, the Commission did not require public utility transmission providers 

 243 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,703-04.

244 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 627.

245 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at PP 66-71.

246 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,707-08.

247Id. at 31,717.
Docket No. RM10-11-000 - 167 -

to offer regulation service for transmission service out of or through the public utility 

transmission provider’s balancing authority area to serve load in another balancing 

authority area.248 

236. Energy imbalance service, offered under Schedule 4 of the pro forma OATT, 

accounts for hourly energy deviations between a transmission customer’s scheduled 

delivery of energy and the actual energy used to serve load.249 In Order No. 888, the 

Commission required public utility transmission providers to offer energy imbalance 

service for transmission service within and into the public utility transmission provider’s 

balancing authority area to serve load in that area.250 Like regulation service, the 

Commission did not require public utility transmission providers to offer energy 

imbalance service for transmission service being used to serve load in another balancing 

authority area.

237. Regulation service and energy imbalance service, while different in function, are 

complementary services through which public utility transmission providers maintain 

their systems’ balance and recover both the capacity (regulation service) and energy 

(energy imbalance service) costs of doing so from transmission customers serving load 

on their systems. At the time of Order No. 888, the Commission believed that it was 

 248Id.

249 Id. at 31,708.

250 Id. at 31,717.
Docket No. RM10-11-000 - 168 -

reasonable to provide only standardized ancillary service schedules for transmission used 

to service load because load (rather than generation) exhibited the greatest amount of 

variability.251 The Commission noted that generators should be able to deliver scheduled 

hourly energy with precision and that the requirements for generators to meet their 

schedules should be contained in interconnection agreements.

238. In Order No. 890, the Commission noted that the existing energy imbalance 

charges were the subject of significant concern and confusion in the industry.252 The 

Commission expressed concern about the variety of different methodologies used for 

determining imbalance charges and whether the level of the charges provided the proper 

incentive to keep schedules accurate without being excessive.253 Such concerns led the 

Commission to revise existing pro forma energy imbalance service provisions and 

require public utility transmission providers to offer a new service, generator imbalance 

service, to account for hourly energy deviations between a transmission customer’s 

scheduled delivery of energy from a generator and the amount of energy actually 

 251 In 1996, when Order No. 888 was developed and issued, wind generation was 

not a significant energy source, with a total capacity of approximately 1,698 MW. See 

Imbalance Provisions for Intermittent Resources; Assessing the State of Wind Energy in 

Wholesale Electricity Markets, Notice of Proposed Rulemaking, FERC Stats. & Regs. 

¶ 32,581, at P 7 (2005). 

252 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 634. 

253 Id.
Docket No. RM10-11-000 - 169 -

generated.

254 The Commission found that formalizing generator imbalance provisions in 

the pro forma OATT would standardize future treatment of such imbalances, thereby 

lessening the potential for undue discrimination, increasing transparency, and reducing 

confusion in the industry that resulted from the then current plethora of different 

approaches.

239. While the pro forma generator imbalance service provides a mechanism for public 

utility transmission providers to recover the cost of providing the energy needed to 

manage hourly generator imbalances, it does not provide a mechanism for public utility 

transmission providers to recover the costs of holding reserve capacity associated with 

providing generator imbalance energy.255 Although the Commission in Order No. 890 

did not create a new rate schedule to expressly account for these capacity costs, it 

acknowledged the likelihood that such costs would be incurred in connection with the 

provision of generator imbalance service.256 Accordingly, the Commission provided a 

mechanism by which public utility transmission providers could recover these costs, 

explaining that “[t]o the extent a [public utility] transmission provider wishes to recover 

costs of additional regulation reserves associated with providing imbalance service, it 

 254 Id. P 663.

255 Id. P 689 (“The Commission concludes that excluding additional regulation 

costs as a general matter is appropriate because much of those costs would be demand 

costs.”).

256 Id. P 690.
Docket No. RM10-11-000 - 170 -

must do so via a separate FPA section 205 filing demonstrating that these costs were 

incurred correcting or accommodating a particular entity’s imbalances.”257 In Order No. 

890-A, the Commission clarified that public utility transmission providers may propose 

to assess regulation charges to generators selling in the balancing authority area, as well 

as generators selling outside the balancing authority area, and that the Commission will 

consider such proposals on a case-by-case basis.258 

a. Commission Proposal

240. In the Proposed Rule, the Commission sought to add a new rate schedule to the 

pro forma OATT that complements the generator imbalance service provided under 

Schedule 9 of the pro forma OATT. The Commission noted that, in order to meet their 

obligations to offer generator imbalance service under Schedule 9, public utility 

transmission providers must hold unloaded resources in reserve to respond to moment-tomoment variations attributable to generation. The Proposed Rule recognized this de facto

obligation and proposed to establish a generic rate schedule (Schedule 10 - Generator 

Regulation and Frequency Response Service) through which public utility transmission 

providers may recover the costs of providing this service. The Commission preliminarily 

found that clarifying the manner by which public utility transmission providers may 

recover the costs associated with fulfilling their obligation to offer this service will 

 257 Id. at P 689 & n.401 (referring to costs associated with capacity used to provide 

generator imbalance service that otherwise are not recovered through Schedule 3).

258 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 313.
Docket No. RM10-11-000 - 171 -

remove barriers to the integration of VERs by eliminating public utility transmission 

providers’ uncertainty regarding cost recovery.259

241. In the Proposed Rule, the Commission stated that Schedule 10 is modeled on 

Schedule 3 - Regulation and Frequency Response Service of the pro forma OATT. 

Where Schedule 3 allows public utility transmission providers to recover the costs of 

regulation reserves associated with variability of load within its balancing authority area, 

proposed Schedule 10 would provide a mechanism through which public utility 

transmission providers can recover the costs of providing regulation reserves associated 

with the variability of generation resources both when they are serving load within the 

public utility transmission provider’s balancing authority area and when they are 

exporting to load in other balancing authority areas.260 

242. The Commission proposed that, consistent with Order No. 890, public utility 

transmission providers would not be permitted to charge transmission customers for 

regulation reserves under both Schedule 3 and Schedule 10 for the same transaction.261 

The Commission emphasized that in establishing Schedule 10, it was not changing the 

 259 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 87.

260 Id. P 88.

261 Id. P 89 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 690 

(requiring transmission providers to demonstrate that any proposals to recover capacity 

costs associated with Generator Imbalance Service do not lead to double recovery); 

Entergy Serv., Inc., 120 FERC ¶ 61,042, at PP 62-66 (2007); Sierra Pac. Res. Operating 

Cos., 125 FERC ¶ 61,026 (2008); Westar Energy Inc., 130 FERC ¶ 61,215, at P 4 

(2010)).
Docket No. RM10-11-000 - 172 -

nature of the services that a public utility transmission provider must offer its 

transmission customers. The Commission stated that nothing in the Proposed Rule would 

affect the manner in which balancing authorities are required to maintain balanced 

systems that are operated in a safe and reliable fashion, consistent with NERC Reliability 

Standards. The Commission explained that it simply proposed to establish a generic cost 

recovery mechanism for a service that public utility transmission providers already are 

obligated to offer customers taking transmission service within their balancing authority 

area.262

243. In the Proposed Rule, the Commission explained that public utility transmission 

providers are not permitted to disclaim the obligation to offer to provide transmission 

customers with the capacity reserves associated with the provision of generator 

imbalance service.263 Therefore, the Commission proposed that, under Schedule 10, a 

public utility transmission provider must offer generator regulation service to the extent it 

is physically feasible to do so from its resources or from resources available to it, to 

transmission customers using transmission service to deliver energy from a generator 

located within the public utility transmission provider’s balancing authority area.264

 262 Id. P 91.

263 Id. P 84 (citing NorthWestern, Corp., 129 FERC ¶ 61,116, at P 27 (2009)).

264 Id. P 89.
Docket No. RM10-11-000 - 173 -

b. Comments

i. Proposed Schedule 10

244. Although several commenters support the Commission’s proposal to establish a 

schedule for the recovery of capacity costs for regulation reserves, much of that support 

is tempered by concern about the scope and design of proposed Schedule 10, as well as 

the flexibility afforded public utility transmission providers to design services relevant to 

recover all costs associated with the integration of VERs under proposed Schedule 10.265 

For example, while EEI indicates that it supports the establishment of a cost recovery 

mechanism for regulation reserves from transmission customers as promoting rate 

certainty and transparency, it also cautions the Commission that the proposal may unduly 

condition cost recovery and may not encompass all cost incurred by the transmission 

provider. While Independent Power Producers Coalition–West supports the concept of a 

generic generator imbalance tariff to bring certainty to disparate tariffs that must now be 

negotiated in WECC, it contends that the Commission should require utilities to revise 

operating agreements, business practices or other procedures such that independently 

owned generator resources are available to balancing authorities in the WECC to reduce 

generator imbalance costs for VERs. Large Public Power Council supports the new 

Schedule 10 provided it is implemented in a way that allows transmission providers to 

receive full compensation for providing the service. 

 265 CMUA at 10-11; EEI at 25-33; Midwest ISO at 14; NRECA at 23-24; 

Organization of Midwest ISO States at 8-9.
Docket No. RM10-11-000 - 174 -

245. NRECA indicates that it also supports the cost recovery proposal embodied in 

proposed Schedule 10; however, it expresses concern that Schedule 10 should not be 

limited to just the recovery of regulation costs, and should instead be expanded to allow

public utility transmission providers the opportunity to demonstrate that additional VER 

integration costs should be recovered through individual Schedule 10s. According to 

NRECA, such costs may include the following: (1) intra-hour schedule implementation 

costs; (2) power production forecasting implementation costs; or (3) other various costs 

such as load-following service, ramping costs, out-of-merit dispatch costs, and additional 

spinning and supplemental reserves, among other things. 

246. Public Power Council and Puget express similar concerns that the proposed 

Schedule 10 would not allow for full recovery of all costs of balancing and integrating 

VERs. According to Public Power Council, Schedule 3 recovers the costs of balancing 

reserves deployed for frequency and regulation control, which in turn leads Schedule 10 

to only recover the costs of regulation (capacity following near instantaneous changes in 

generation) but not the costs arising from either load following capacity (capacity used 

minute-to-minute over approximately a 10-minute period) or capacity needed to make up 

a variable generator’s schedule error for the scheduling period. Public Power Council

also argues that Schedule 10 charges should include the costs of power production 

forecasting systems as these would not be needed but for the integration of variable 

generation. The PNW Parties agree and suggest that Schedule 10 should be expanded 

further to allow for the recovery of all costs incurred by the public utility transmission 

provider in providing regulating reserves that are not recoverable through the generation 
Docket No. RM10-11-000 - 175 -

imbalance rate, including but not limited to, extra energy costs and operation and 

maintenance costs. 

247. Southern states that the capacity required to provide generator imbalance service 

or otherwise respond to operational challenges presented by substantial swings in output 

from generators (particularly VERs) may mostly be conceptualized as providing a 

“regulation” service, but it should be understood that some public utility transmission 

providers may also incur additional costs that may implicate other ancillary services, such 

as reactive power and load following, if not contingency response. Southern asserts that 

the Commission should not categorically foreclose or limit in advance the right of public 

utility transmission providers under section 205 to file tariffs or tariff amendments on a 

case-by-case basis to recover any and all additional reasonable costs specific to VERrelated regulation reserve requirements. Southern requests that the Commission confirm 

that the invitation in Order No. 890 for public utility transmission providers to file rate 

schedules and amendments to address costs of generator imbalances on a case-by-case 

basis remains open.

248. Public Interest Organizations contend that it may be unjust and unreasonable to 

charge VERs regulation rates for capacity requirements that can be addressed by less 

expensive ancillary services. Public Interest Organizations state that the Commission 

could address this problem either by reforming Schedule 10 into a slower service akin to 

load-following or non-spinning reserves, or by clarifying that Schedule 10 is designed to 

compensate only for the moment-to-moment balancing associated with generation 
Docket No. RM10-11-000 - 176 -

variability, and not for VER variability that affects the system beyond the balancing 

timeframe. 

249. AWEA suggests that the Commission focus on such longer-term variability, 

requesting that the Commission reformulate proposed Schedule 10 as a system nonspinning service to accommodate the aggregate system variability that is not 

accommodated through other ancillary services. AWEA states that this type of service 

would benefit all users of the system by providing inexpensive reserves to accommodate 

all types of gradual variability on the power system, including changes driven by 

inaccurate load forecasts, changes in demand driven by large electricity users, as well as 

aggregate changes of many small users. AWEA notes that wind and solar exhibit little 

variability over the regulation time period while variability over the course of an hour can 

be more significant. AWEA argues that a system non-spinning service would be wellsuited for accommodating the incremental increase in system variability caused by the 

addition of such resources.

250. Similarly, Iberdrola recommends the Commission structure Schedule 10 as a 

following reserves service rather than regulation reserve, arguing that the rate of change 

associated with wind ramps is not instantaneous but rather occurs over longer time 

periods within the hour and often for multiple hours. To the extent that the Commission 

does not reformulate Schedule 10 in this way, Iberdrola requests that the Commission 

convene a technical conference that focuses on the ancillary services needed to support 

VERs. NextEra agrees that the Commission should convene a technical conference to 
Docket No. RM10-11-000 - 177 -

address what kind of ancillary services should be developed to complement the growth of 

VERs, among other things.

251. Duke suggests that the Commission should unbundle regulation and frequency 

response service into separate ancillary service schedules. In support, Duke points to 

such industry activities as NERC developing a revision to Frequency Response 

Reliability Standard BAL-003-0, which will prescribe specific amounts of frequency 

response that each balancing authority must procure; the Commission report prepared by 

the Lawrence Berkeley National Laboratory, which discusses operational characteristics 

and distinctions of primary and secondary frequency control reserves (Docket No. AD11-

8-000); and the Commission’s Notice of Proposed Rulemaking in Docket Nos. RM11-7-

000 and AD10-11-000, which also distinguishes frequency response from regulation.

252. American Clean Skies argues that the Proposed Rule should require RTOs to offer 

additional ancillary services, such as load following (on a minute-to-minute basis), 

reactive power and other comparable backup capabilities. Coalition for Green Capital 

similarly asks the Commission to encourage the development of power and ancillary 

services products that match the technical and commercial capabilities of VERs to allow 

VERs to integrate into the bulk power grid at rates and on terms and conditions that are 

just and reasonable and not unduly discriminatory or preferential. Independent Energy 

Producers assert that, while it is critical that ancillary service products be identified and 

developed to permit VERs to be integrated, it is equally critical that the necessary 

compensation measures be developed to ensure that dispatchable generation is available 
Docket No. RM10-11-000 - 178 -

when and where it is needed to support the ancillary services products, particularly within 

the California ISO market. 

253. With regard to charging transmission customers under both Schedule 3 and the 

proposed Schedule 10, Bonneville Power agrees with the Commission’s decision in 

Order No. 890 regarding the potential for double recovery if energy settlement charges 

(under Schedules 4 and 9 of the OATT) are imposed on both the generator and load when 

they reside in the same balancing authority, but argues that there are significant 

differences between energy settlement charges and capacity charges recovered under 

Schedule 3 and Proposed Schedule 10. Bonneville Power states that the public utility 

transmission provider must maintain balancing reserve capacity for movement of both the 

load and the generators located in its balancing authority area because the deviations 

from schedule for the load and generation move independently from one another, and that 

the transmission provider should be allowed to recover costs for capacity it is providing 

to both generation and load. 

254. Duke similarly argues that the Commission should allow the public utility 

transmission provider to recover both Schedule 3 and 10 costs if both services are utilized 

by the transmission customer. Duke contends that it is appropriate in some circumstances 

to charge a load for Schedule 3, and a generator for Schedule 10, even if they are owned 

by the same party. According to Duke, unless the generator is coupled to the load by an 

energy management system (i.e., the generator is controlling to the load), or the generator 

is dynamically serving a load (i.e., where its output can be controlled to match the load it 

serves), a public utility transmission provider should be permitted to charge for both 
Docket No. RM10-11-000 - 179 -

Schedule 3 and Schedule 10 as they are two different services which can be provided at 

the same time (e.g., where a load serving entity owns load within a control area, as well 

as a generator). 

255. Finally, several commenters contend that Schedule 10 is not necessary in 

organized markets.266 PJM interprets Schedule 10 as optional and seeks clarification that 

this interpretation is correct. Sunflower and Mid-Kansas submit that the SPP market 

rules already are consistent with or superior to the pro forma OATT as the Commission 

proposes to amend it in this Proposed Rule and believes it is highly likely that all of the 

other RTOs’ rules are also superior to what has been proposed. Clean Line contends that 

the potential of double recovery exists for generators receiving compensated through 

organized market mechanisms. AWEA contends that the Commission should clarify that 

the creation of Schedule 10 service should apply only in areas of the country that do not 

have functioning ancillary services markets. Likewise, Iberdrola explains that a Schedule 

10-type product is not necessary in organized markets, as most organized markets 

balance the system’s energy and reserve requirements through use of simultaneously cooptimized Security Constrained Unit Commitment and Security Constrained Economic 

Dispatch algorithms that clear and dispatch energy and reserves. 

 266 E.g., AWEA; California ISO; Iberdrola; ISO New England, New York ISO; 

Sunflower and Mid-Kansas.
Docket No. RM10-11-000 - 180 -

ii. Obligation to Offer Generator Regulation Service

256. Several commenters seek clarification regarding the extent to which the public 

utility transmission provider must provide generator regulation service. NaturEner states 

that public utility transmission providers should not be able to avoid providing regulating 

reserves based upon claims that they themselves do not own generation in sufficient 

amounts to supply the service. Xtreme Power asks that the Commission make clear that, 

in the event that a public utility transmission provider’s existing resources are not 

adequate to meet the obligation to provide generator regulation service and new resources 

are needed to accommodate additional variability, the public utility transmission provider 

is obligated to procure a sufficient quantity of the appropriate resources. 

257. Grant PUD asks whether a public utility transmission provider must procure 

additional regulation resources if the demand for these services exceeds the contractual 

and owned resources available to the public utility transmission provider that can provide 

regulation service at the time of the request for service. NorthWestern requests that the 

Commission clarify that the phrase “or from resources available to it” refers to 

acquisition of generator regulation service from third parties and is not intended to mean 

that, if the utility does not have access to its own resource or resources from the market, 

the utility must build generation for Schedule 10 service. Independent Power Producers 

Coalition–West states that transmission providers should not be permitted to charge 

VERs for generator imbalance services unless they provide VERs with the capability to 

obtain those services from third parties on a non-discriminatory basis. If a public utility 

transmission provider does not have access to its own resources or resources from the 
Docket No. RM10-11-000 - 181 -

market and chooses to build new generation to offer Schedule 10 service, EEI asks the 

Commission to clarify that these costs can be recovered from the resources that trigger 

the need to build. EEI also states that the language “or from resources available to it” 

could be read to require the public utility transmission provider to violate reliability 

standards by using resources set aside for contingency reserves to support generation 

regulation service.267 EEI requests that the Commission clarify the statement as follows: 

“a public utility transmission provider must offer generator regulation service; to the 

extent it is physically feasible to do so from its existing resources or from resources 

currently available to it, without violating applicable reliability standards.”268 

258. Puget asks that the Commission clarify that public utility transmission providers 

are only required to provide Schedule 10 service within a defined confidence interval 

commensurate with the public utility transmission provider’s level of regulation capacity 

set aside for cost recovery under the Schedule 10. If those resources’ capabilities are 

exceeded or if system conditions otherwise warrant, Puget suggests that the public utility 

transmission provider should retain the right to curtail generation production or export 

schedules to preserve reliability. Public Power Council and Bonneville Power also 

question whether the obligation to provide generator regulation service is unlimited, 

suggesting that such service could require firming of every generation delivery, which 

 267 EEI at 32.

268 Id..
Docket No. RM10-11-000 - 182 -

would be extremely expensive. Bonneville Power contends that the source balancing 

authority should have the ability to offer a base level quantity of balancing reserve 

capacity and should have the right to use operational tools to limit the deployment of 

reserves to that quantity. In support, Bonneville Power explains that it has developed 

Dispatcher Standing Order 216 (DSO 216) to require reductions in wind generation or 

changes to wind generators’ transmission schedules when the schedule error of the wind 

fleet exhausts the total amount of balancing reserve capacity that Bonneville Power has 

made available for wind and load. 

259. Bonneville Power states that it is currently providing enough balancing reserve 

capacity to meet the needs of the wind fleet in its balancing authority during 99.5 percent 

of the forecast VER variability events. Bonneville Power describes the remaining 0.5 

percent as representing the most extreme variability in VER generation (i.e., “tail 

events”). Because of the substantial wind generation exports from Bonneville Power’s 

balancing authority area, Bonneville Power explains that it needs a mechanism to “clip 

the tails” of wind ramps when they exhaust the total amount of balancing reserve capacity 

that Bonneville Power makes available for wind and load. Bonneville Power states that 

DSO 216 allows it to establish the amount of balancing reserve capacity that will be 

deployed and, because there is a set limit, it is able to quantify its obligation and risks for 

rate setting, system planning, and reliability purposes. Bonneville Power contends that a 

requirement to maintain balancing reserve capacity at all times to manage tail events 

would be significantly expensive.
Docket No. RM10-11-000 - 183 -

260. Bonneville Power also asks the Commission to clarify that the public utility 

transmission provider is required to offer to provide Schedule 10 service only to the 

extent it can do so without harming system reliability or risking non-compliance with 

state and Federal law and other non-power requirements that affect system operations. 

Snohomish County PUD and Grays Harbor PUD similarly ask the Commission to clarify 

that Bonneville Power should not be required to offer capacity from the Federal System 

to meet demand for services under Schedule 10 where that capacity is not available due 

to statutory and regulatory obligations that limit the availability of the Federal System’s 

capacity. Grays Harbor PUD adds that the Commission should make clear that, during 

periods when Bonneville Power’s system is limited by statutory and regulatory 

constrains, it is not “physically feasible” for Bonneville Power to use that capacity to 

support integration of VERs and, therefore, during those periods is exempt from 

requirements to do so. Bonneville Power further requests that the Commission clarify 

that the public utility transmission provider is obligated to provide generator regulation 

service pursuant to Schedule 10 and generator imbalance service pursuant to Schedule 9 

only to the extent that balancing reserve capacity is made available pursuant to Schedule 

10. In addition, Bonneville Power suggests that the Commission should address the 

pricing policy articulated in the Avista line of cases, which restricts public utility 

transmission providers that are not in organized markets to recovering cost-based rates 

for ancillary services, to ensure public utility transmission providers have the ability to 
Docket No. RM10-11-000 - 184 -

obtain the necessary balancing reserve capacity.269 Tres Amigas concurs with Bonneville 

Power and suggests that the Commission alter its approach so that these services can be 

bought and sold competitively outside of organized RTO markets as they are in most 

RTOs.

iii. Self-supply of Generator Regulation Service

261. First Wind asks the Commission to clarify that Schedule 10 charges would be 

imposed on VERs only to the degree they take transmission service or otherwise elect to 

take Schedule 10 service. AEP contends that the Proposed Rule contains a loophole in 

that purchasers of VER energy outside of the resource’s native balancing authority’s 

footprint would be able to avoid any ancillary service charges caused by their purchase 

and transport of energy. Other commenters discuss how the balancing authority into 

which generation is dynamically scheduled would be compensated for providing 

regulation service.270 These commenters contend that because the sink balancing 

authority is providing the regulation service for that generator in these situations, it 

should be clear in Schedule 10 that the sink balancing authority will be paid for providing 

that service.

 269 Bonneville Power (referencing Avista Corp., 87 FERC ¶ 61,223 (1999); 

Market-Based Rates For Wholesale Sales Of Electric Energy, Capacity And Ancillary 

Services By Public Utilities, Order No. 697, 119 FERC ¶ 61,295 (2007) (Order No. 697)).

270 E.g., Duke; EEI; Exelon. 
Docket No. RM10-11-000 - 185 -

262. Commenters address the option for transmission customers to self-supply 

generator regulation service. Bonneville Power states that it recognizes that VERs may 

find it economical to self-supply balancing reserve capacity to provide balancing service 

and asks the Commission to clarify in Schedule 10 that a customer electing to self-supply 

is subject to the public utility transmission provider’s requirements for Schedule 10 

service and the transmission provider’s reliability and operational protocols, including 

any transmission curtailments and generation limitations in the event the self-supplying 

VER fails to meet the transmission provider’s standards. Powerex agrees that the public 

utility transmission provider should have discretion to decide whether a method of selfsupply is acceptable but argues that the public utility transmission provider should be 

required to describe what it considers to be acceptable comparable arrangements in 

posted business practices. 

263. Xtreme Power similarly contends that, in order for self-supply or third-party 

procurement of generator regulation service to be a viable option, the public utility 

transmission provider must specify how a customer’s generator regulation service

requirements are determined and how the requirements may be satisfied through selfsupply or third-party procurement. NaturEner contends that the self-supply provision 

should be administered on a flexible basis and this could include use of self-curtailment, 

carrying of a portion of the regulating reserve capacity on a dynamic basis, and carrying 

of a varying level of regulating reserves because a constant level is not necessary. 

Independent Power Producers Coalition–West argues that public utility transmission 

providers should only be permitted to charge VERs for generator imbalance services if 
Docket No. RM10-11-000 - 186 -

they provide VERs with the capability to obtain those services from third parties on a 

non-discriminatory basis.

264. Beacon Power indicates that entities subject to Schedule 10 should be allowed to 

work with public utility transmission providers in non-RTO/ISO markets to determine 

different volumes of self-supplied regulation reserve capacity required based on the 

ramp-rate capability of its regulation resource(s). CESA agrees that, if a transmission 

customer subject to the Schedule 10 chooses to self-supply its regulation reserve 

capacity, the amount of capacity self-supplied should account for the fact that a MW of 

reserve capacity from a fast-ramping resource provides more regulation value to the grid 

per MW than a slow-ramping resource. NEMA indicates that some resources that 

provide generator regulation service, such as batteries and flywheels, can dampen 

variations much more quickly than can traditional generators. Therefore, NEMA 

contends that the generator regulation service requirements should be based on the 

amount of generator regulation service actually provided, rather than solely the capacity 

of regulation service. A123 recommends that the Commission clarify the phrase 

“alternative comparable arrangements” to include resources that may differ in MW 

capacity but supply equivalent or superior regulation performance when compared to the 

public utility transmission provider’s default service. 

265. Powerex asks that the Commission confirm that self-supply includes the ability of 

the transmission customer to self-supply by purchasing regulation reserve capacity from 
Docket No. RM10-11-000 - 187 -

third parties.271 Powerex states that it could be helpful for the Commission to provide 

guidance on what should qualify as an “alternative comparable arrangement.” SEIA 

supports providing transmission customers with the opportunity to avoid regulation 

service costs through dynamic scheduling or self-supply arrangements, but ask the 

Commission to clarify how self-supply would allow solar plants to avoid regulation 

reserve requirements, which SEIA believes would assign a constantly varying share of 

the Schedule 10 requirement to a solar plant capable of providing regulation service. The 

Federal Trade Commission asserts that the self-supply option under Schedule 10 is vague 

and should recognize that VERs could address their regulation requirements by matching 

their generation variability to demand variability.

266. Other commenters request that additional requirements be included in Schedule 10 

with regard to self-supply. CGC states that the Proposed Rule fails to require public 

utility transmission providers to provide dynamic transfer capability out of their 

balancing authority area or provide an ancillary services market through which a 

generator could self-supply generator regulation service. CGC asks the Commission to 

require all public utility transmission providers, either by themselves or in association 

with other public utility transmission providers, to provide access to a fully functioning 

competitive ancillary services market and/or dynamic transfer capabilities. ELCON 

asserts that the Commission should specify that public utility transmission providers must 

 271 Powerex at 22.
Docket No. RM10-11-000 - 188 -

consider using dispatchable demand response resources to provide Schedule 10 service. 

CESA recommends that FERC allow Schedule 10 self-supply requirements to vary based 

on the ramp-rate of the resources providing the service, offering that faster-acting 

resources provide more ACE correction than slower resources.

c. Commission Determination

267. The Commission declines to amend the pro forma OATT to include a standardized 

ancillary services schedule for generator regulation services as proposed in the Proposed 

Rule. As indicated above, the Commission intended for proposed Schedule 10 to be a 

clearly defined mechanism for public utility transmission providers to recover the costs of 

capacity held in reserve to provide generator imbalance service under Schedule 9 of the 

pro forma OATT, while also providing customers with certainty as to the rates they will 

be required to pay when taking this service. The Commission also sought to confirm the 

right of public utility transmission providers to recover the reasonably incurred costs of 

providing this capacity service and to distinguish, where appropriate, among classes of 

customers who cause such costs to be incurred. 

268. In response to the Proposed Rule, the Commission received numerous comments 

urging flexibility in the design of capacity services needed to integrate VERs into 

transmission systems, suggesting that the proposed pro forma generator regulation 

service may not be the most efficient and economical service with which to integrate 

VERs. For example, Southern notes that the recovery of capacity costs incurred to 

provide Schedule 9 generator imbalance service could implicate a range of services, from 

regulation to load following, depending on how the public utility transmission provider 
Docket No. RM10-11-000 - 189 -

conceptualizes the service provided. Iberdrola suggests that VER integration has more 

significant implications for within hour spinning and non-spinning capacity than 

moment-to-moment regulation capacity. In light of these comments, the Commission 

concludes that the adoption of a standardized pro forma Schedule 10 could inhibit the 

flexibility commenters seek to design capacity services that align with the operational 

needs of a particular public utility transmission provider. Accordingly, the Commission 

declines to adopt the proposed Schedule 10 component of the Proposed Rule and will 

continue to evaluate proposals to recover capacity costs incurred to provide Schedule 9 

generator imbalance service on a case-by-case basis. In this way, public utility 

transmission providers will remain free to propose capacity services that best respond to 

the needs of their customers and will not have to expend resources adopting the one-sizefits-all generator regulation service discussed in the Proposed Rule, even in situations 

where some other service or rate design may be more appropriate. 

269. To be clear, the Commission emphasizes that our decision not to implement a 

generic rate schedule for generator regulation service should not be interpreted as an 

unwillingness to consider individual proposals brought by public utility transmission 

providers. The Commission recognizes that a public utility transmission provider may 

incur capacity costs associated with fulfilling obligations to provide Schedule 9 generator 

imbalance service and that existing rate mechanisms may be inadequate for some public 

utility transmission providers to properly allocate and recover those costs. For many 
Docket No. RM10-11-000 - 190 -

years, the Commission has evaluated proposals to recover such capacity costs on a caseby-case basis in light of the specific facts and circumstances in each case.272 The 

Commission concludes that continuation of this case-by-case approach is more 

appropriate to tailor the particular capacity services needed by a public utility 

transmission provider to its operations. At the same time, the Commission is sensitive to 

commenter requests to provide guidance regarding the proper design of a generator 

regulation service charge should a public utility transmission provider desire to propose 

one. In the section that follows, the Commission provides a framework that can be used 

for those public utility transmission providers seeking to develop a proposal to recover 

capacity costs incurred to provide Schedule 9 generator imbalance service.273

 272 See Florida Power Corp., 89 FERC ¶ 61,263, at 61,765 (1999) (Florida 

Power) (“The Commission concludes that a generator imbalance capacity obligation is 

imposed on the transmission provider for export transactions, and therefore the 

Commission accepts Florida Power Corp’s Generator Regulation Service as a reasonable 

proposal in those circumstances where the service is not already covered in an 

interconnection agreement or a separate generator tariff.”); Entergy, 120 FERC ¶ 61,042 

at PP 62-66 (accepting a generator regulation service rate schedule for independent power 

producers selling out of the control area that retained charges that had been previously 

negotiated between Entergy and the relevant independent power producers); Sierra Pac. 

Res. Operating Cos., 125 FERC ¶ 61,026, at P 10 (2008) (accepting a generator 

regulation service rate schedule to provide the capacity necessary to follow the momentto-moment changes caused by generators selling outside of the transmission provider’s 

control area).

273 See infra § IV.C.2 (Mechanics of a Generator Regulation Charge). While this

section is framed primarily in terms of a generator regulation service, the principles 

discussed would also apply more broadly to other capacity services designed to recover 

capacity costs incurred to provide Schedule 9 generator imbalance service.
Docket No. RM10-11-000 - 191 -

270. Before turning to the mechanics of a generator regulation service charge, the 

Commission clarifies in response to comments that our decision not to adopt a generic 

Schedule 10 does not relieve public utility transmission providers of obligations under the 

pro forma OATT to provide Schedule 9 generator imbalance service. This in turn 

requires the public utility transmission provider to maintain sufficient capacity to provide 

that service.274 However, as the Commission explained in Order No. 890-A, if it is not 

physically feasible for a transmission provider to offer generator imbalance service using 

its own resources, either because they do not exist or they are fully subscribed, the public 

utility transmission provider must attempt to procure alternatives to provide the service, 

taking appropriate steps to offer an option that customers can use to satisfy their 

obligation to acquire generator imbalance service as a condition of taking transmission 

service.275 The Commission explained that each transmission provider can state on its 

OASIS the maximum amount of generator imbalance service it is able to offer from its 

resources, based on an analysis of the physical characteristics of its system. 

Alternatively, a public utility transmission provider may consider requests for generator 

imbalance service on a case-by-case basis, performing, as necessary, a system impact 

 274 NorthWestern Corp., 129 FERC ¶ 61,116, at P 24 (2009), order denying reh’g, 

131 FERC ¶ 61,202, at PP 17-18 (2010).

275 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at PP 289-90.
Docket No. RM10-11-000 - 192 -

study to determine the precise amount of additional generation it can accommodate and 

still reliably respond to the imbalances that could occur.276 

271. Because a proposal for generator regulation service would be associated with 

generator imbalance service, it follows that the public utility transmission provider would 

use a similar analysis to identify any limitations on its ability to offer either service.277 

Just as it can for generator imbalance service, the public utility transmission provider 

could explain on its OASIS the maximum amount of generator regulation service it is

able to offer after having attempted to procure alternative resources to provide the 

service. Alternatively, the public utility transmission provider could perform a system 

impact study to determine the precise amount of generator regulation service it can 

provide. In response to NorthWestern, this Final Rule does not place any obligation on 

the public utility transmission provider to build generation.

272. With regard to comments regarding self-supply of ancillary services, the 

Commission acknowledges that self-supply may come from many sources, including 

purchased capacity and the use of non-generation resources, as suggested by ELCON. 

The option to self-supply certain ancillary services has been in place since Order No. 888, 

and the Commission declines here to specify any particular requirements for self-supply 

 276 Id. P 289.

277 In the unlikely event that there are no additional resources available to enable 

the public utility transmission provider to meet its obligation to offer generator regulation 

service, the public utility transmission provider must accept the use of dynamic 

scheduling with a neighboring control area. See id. P 290.
Docket No. RM10-11-000 - 193 -

arrangements for generator regulation service proposals. To do so could restrict 

flexibility to develop competitively priced options tailored to particular customer needs. 

As suggested by some commenters, such options could include the use of faster ramping 

resources to provide the service. 

273. In response to Powerex, the Federal Trade Commission and others, the 

Commission does not believe that the self-supply option is vague or that additional 

guidance is necessary on what should qualify as an “alternative comparable 

arrangement.” The Commission notes that public utility transmission providers already 

are obligated to post on their public websites all rules, standards, and practices, to the 

extent they exist, that relate to transmission service.278 The provision of ancillary 

services is necessary to accomplish transmission service and, therefore, we conclude this 

posting obligation applies equally to ancillary services279. Public utility transmission 

providers must post any rules, standards, and practices regarding self-supply 

requirements pursuant to their obligation to allow self-supply of ancillary services.280 

The Commission declines to adopt further requirements at this time regarding the selfsupply of ancillary services.281

 278 Order No. 890, FERC Stats.& Regs. ¶ 31,241 at P 1652. 

279 The Commission notes that this obligation is subject to audit as are all other 

OATT requirements.

280 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,705.

281 Id.
Docket No. RM10-11-000 - 194 -

274. In response to the Federal Trade Commission, the Commission encourages 

transmission providers, generators, and transmission customers to work together to 

explore options to find the least cost methods of balancing the system as a whole and to 

provide maximum flexibility for products and services that meet the needs of the 

customers and the transmission providers alike. This includes, for example, evaluating 

the extent to which regulation service obligations can be addressed by matching 

generation variability to demand variability, as suggested by the Federal Trade 

Commission. Indeed, in Order No. 888, the Commission stated that the pricing of 

ancillary services should include the amount of each ancillary service that the 

transmission customer must purchase, self-supply, or otherwise procure and must be 

readily determinable from the transmission provider’s tariff and comparable to 

obligations to which the transmission provider itself is subject.282 The Commission also 

specified that the transmission provider is required to identify the regulating margin 

requirements for transmission customers serving loads in its balancing authority area and 

to develop procedures by which customers can avoid or reduce such requirements.283 

 282 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,721. 

283 Id. at 31,717. Order No. 890 did not alter the requirements of Order No. 888 in 

this regard, but did clarify that regulation and frequency response, as well as imbalance 

energy, may be provided by public utility transmission providers or through self-supply 

using generating units as well as other non-generation resources such as demand 

resources where appropriate. Order No. 890, FERC Stats. & Regs. ¶ 21,241 at P 888.
Docket No. RM10-11-000 - 195 -

275. For reasons explained elsewhere in this Final Rule, the Commission declines to 

adopt CGC’s suggestion to require transmission providers to provide dynamic transfer 

capability out of their balancing authority area or mandate the creation of an ancillary 

services market through which a generator could self-supply generator regulation 

service.

284

2. Mechanics of a Generator Regulation Charge

276. The Proposed Rule stated that, as with Schedule 3, the proposed Schedule 10 

charge would be the product of two components: a per-unit rate for regulation reserve 

capacity, and a volumetric component for regulation reserve capacity.285 The 

Commission proposed to require each public utility transmission provider to submit a 

compliance filing that includes the addition of a Generator Regulation and Frequency 

Response rate schedule to the OATT that includes the same per unit rate from their 

currently effective Regulation and Frequency Response rate schedule and a blank or 

unfilled volumetric component.286 

 284 See supra IV.A.1 (Intra-Hour Scheduling Requirement).

285 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 92. The Commission is 

exploring potential reforms to ancilliary services pricing in other proceedings. See 

Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for 

New Electric Storage Technologies, Notice of Proposed Rulemaking, 139 FERC ¶ 61,245 

(2012) (NOPR).

286 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 101. 
Docket No. RM10-11-000 - 196 -

277. The Commission preliminarily found that the per-unit rate for service under 

proposed Schedule 10 should be the same as the rate for service under existing Schedule 

3.287 The Commission explained that Schedule 3 and the proposed Schedule 10 are both 

designed to recover the costs of holding regulation reserve capacity to meet system 

variability. Because the service provided under both schedules is functionally equivalent, 

the Commission proposed to find that it is just and reasonable to use the same rate 

currently established in a public utility transmission provider’s Schedule 3 when charging 

transmission customers under Schedule 10. The Commission stated that, for a public 

utility transmission provider to apply a different rate under the proposed Schedule 10, the 

public utility transmission provider would have to demonstrate that the per-unit cost of 

regulation reserve capacity is somehow different when such capacity is utilized to address 

system variability associated with generator resources. The Commission also noted that 

the use of a common rate is consistent with Commission policy utilizing the same rate 

structure for energy and generator imbalance service, as well as the generator regulation 

rate that the Commission accepted in Westar Energy Inc.288 

278. With regard to the volumetric component of the Schedule 10 rate, the Commission 

proposed to provide each public utility transmission provider with the opportunity to 

justify a proposal: (1) to require all transmission customers who are delivering energy 

 287 Id. P 94.

288 Id. P 93 (citing Westar Energy Inc., 130 FERC ¶ 61,215 (2010) (Westar)).
Docket No. RM10-11-000 - 197 -

from generators to purchase, or otherwise account for, the same volume of generator 

regulation reserves; or (2) to require transmission customers who are delivering energy 

from VERs to purchase, or otherwise account for, a different volume of generator 

regulation reserves than it proposes to charge transmission customers delivering energy 

from other generating resources.289 The transmission provider’s proposal would be made 

in a section 205 filing after the acceptance of its compliance filing. 

279. Where a public utility transmission provider proposes the same volume of 

generator regulation reserves for all generators, the Commission proposed that it 

demonstrate that the volume of regulation reserves required of transmission customers 

delivering energy from generators located within its balancing authority area be 

commensurate with their proportionate effect on net system variability, taking account of 

diversity benefits.290 The Commission stated that such a filing must show that the public 

utility transmission provider has fully implemented (or been granted waiver from) the 

 289 The Commission noted its expectation that, in any subsequent filing to establish 

a volumetric component in Schedule 10, public utility transmission providers would 

address how Schedule 10 and Schedule 3 work together to allow for the recovery of total 

regulation reserve costs. Id. P 105 & n.206.

290 The Commission explained that diversity benefits result from the aggregation 

of the variations of all resources such that one resource’s negative deviation can offset 

some or all of another resource’s positive deviation. The Commission stated that, when 

the transactions of two customers result in diversity benefits, it is incorrect to say that one 

customer is benefitting the other but not vice versa. Instead, the Commission 

preliminarily found that diversity benefits would result from both transactions and that 

sharing of these benefits among the customers would be reasonable. Westar,130 FERC 

¶ 61,215 at P 37.
Docket No. RM10-11-000 - 198 -

intra-hourly scheduling requirement set forth in the Proposed Rule.291 The Commission 

recognized that a public utility transmission provider with few VERs located in its 

balancing authority area may choose to apply only one volumetric regulation requirement 

for all generating resources in its balancing authority area. The Commission noted that 

this also may be the case to the extent the impact of VERs on a public utility transmission 

provider’s system is minimal and the public utility transmission provider, in its judgment, 

deems the administrative burden of justifying two separate volumetric regulation 

requirements is uneconomic.292

280. The Commission proposed that where a public utility transmission provider 

proposes to require transmission customers who are delivering energy from VERs to 

purchase, or otherwise account for, a different volume of generator regulation reserves 

than it proposes to charge transmission customers delivering energy from other 

generating resources, the Commission proposed that it demonstrate that the volumes of 

regulation reserves required of those subsets of transmission customers delivering energy 

from generators located within its balancing authority area are commensurate with their 

proportionate effect on net system variability and taking account of diversity benefits.293 

That is, any proposal for different volumes of generator regulation reserves based on the 

 291 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 105.

292 Id. P 94.

293 Id. P 106.
Docket No. RM10-11-000 - 199 -

generating resource would need to be supported by data showing that, on the public 

utility transmission provider’s system, VERs have a different per unit impact on overall 

system variability than conventional generating units.294 The Commission proposed that 

such a filing must also show that the public utility transmission provider has fully 

implemented (or been granted waiver from) the intra-hourly scheduling requirement set 

forth in the Proposed Rule and has developed and deployed power production forecasting 

for VERs.295 

281. Specifically, the Commission proposed that any filing by public utility 

transmission providers including different volumetric requirements for different subsets 

of transmission customers must be supported with actual data collected over a one-year 

period subsequent to the deployment of power production forecasting for VERS and the 

implementation of intra-hourly scheduling at 15-minute intervals. The Commission 

acknowledged that this proposal could delay a public utility’s ability to recover the cost 

associated with providing generator regulation service. The Commission further 

acknowledged that there may be alternative methods for developing the data necessary to 

support different volumetric requirements for different subsets of transmission customers. 

The Commission sought comment as to such methods of demonstration, how they could 

support a Commission finding that the Schedule 10 filing is just and reasonable, and 

 294 Id. P 95.

295 Id. P 106.
Docket No. RM10-11-000 - 200 -

ways in which these methods of demonstration may be preferable to this aspect of the 

Commission’s proposal.296

282. In the Proposed Rule, the Commission stated that the increased use of power 

production forecasts in transmission systems where VERs are located can provide 

transmission providers with improved situational awareness, enable transmission 

providers to utilize existing system flexibility through the unit commitment and dispatch 

processes, and, ultimately, lead to a reduction in the amount of reserve products needed 

to maintain system reliability. The Commission also recognized that, in areas of the 

country with very limited production from VERs, the implementation of power 

production forecasting for VERs could be less useful.297 The Commission sought 

comment in the Proposed Rule on the manner by which a public utility transmission 

provider should be required to show it has developed and deployed power production 

forecasts to support a proposal to require a differentiated volumetric component of rates 

for generator regulation reserves under proposed Schedule 10.298

 296 Id. P 107.

297 Id. P 55 n.125. 

298 Id. P 106.
Docket No. RM10-11-000 - 201 -

a. Comments

i. General

283. Invenergy Wind requests that the Commission clarify that, in requiring initial 

Schedule 10 charges to adopt the utility’s then-effective Schedule 3 charges, the 

application of the rate will be consistent. Invenergy Wind states that Schedule 3 charges 

are typically applied on the basis of a percentage of the customer’s schedule. Beacon 

Power questions the reliance on existing regulation service charges, stating that a 

transmission provider in non-RTO/ISO markets could optimize the performance of its 

existing fleet to potentially lower costs to customers under Schedule 3 or 10. Beacon 

Power requests that the Commission encourage such transmission providers to evaluate 

the technologies and benefits they provide. Xtreme Power agrees, asking the 

Commission to require public utility transmission providers to make a showing that the 

rates proposed for Schedule 10 are based on an appropriate type and quantity of resources 

needed, considering the technologies available in the market today rather than using 

dated rates from Schedule 3. CESA suggests that the reforms proposed for Schedule 3 in 

the Commission’s Frequency Regulation Notice of Proposed Rulemaking be included in 

Schedule 10 for RTO and ISO markets.299

 299 CESA; See also Notice of Proposed Rulemaking on Frequency Regulation 

Compensation in the Organized Wholesale Electric Markets, 134 FERC ¶ 61,124 (2010) 

(Frequency Regulation NOPR); Frequency Regulation Compensation in the Organized 

Wholesale Power Markets, Order No. 755, 76 FR 67260 (Oct. 31, 2011), FERC Stats. & 

Regs. ¶ 31,324 (2011), reh’g denied, Order No. 755-A,138 FERC ¶ 61,123 (2012). 
Docket No. RM10-11-000 - 202 -

284. Some commenters suggest that public utility transmission providers be permitted 

to recover opportunity costs associated with providing generator regulation service.300 

For example, the Large Public Power Council states that, consistent with the decision in 

Puget, generator regulation service rates should be fully compensatory, and may 

legitimately reflect a utility’s full opportunity cost.301 According to Puget, there may also 

be lost opportunity costs associated with reserving unloaded generation capacity during 

peak market conditions. NRECA argues the integration of a significant amount of VERs 

will cause the Schedule 3 rate to rise as Schedule 10 demand increases particularly in 

regions with a lot of hydropower, where the additional VERs cause the need for more 

thermal reserves, which are more expensive than the existing reserve rate base.

ii. Quantity of Reserves

285. Some commenters request further direction from the Commission regarding the 

calculation of the volumetric component of Schedule 10, i.e., the quantity of reserves 

transmission customers are required to purchase or otherwise account for.302 For 

example, the California PUC asserts that the Commission should recommend or require 

that a public utility transmission provider consider the system’s resource mix and the 

amount of operational flexibility of the transmission system’s generation fleet to develop 

 300 E.g., SMUD; WUTC; EEI; Large Public Power Council; Puget. 

301 E.g., Large Public Power Council (citing Puget Sound Energy, 132 FERC 

¶ 61,128 (2010)).

302 E.g., CPUC; LADWP; SEIA.
Docket No. RM10-11-000 - 203 -

the volumetric component of Schedule 10. LADWP indicates that measures of alleged 

diversity benefits may lead to unintended results if significant diversity occurs in one part 

of a year and forms the basis for a smaller volumetric component than is necessary for 

another part of the year.

286. Some commenters question whether the Commission should allow public utility 

transmission providers the opportunity to file for differentiated volumetric rates under 

Schedule 10. AWEA contends that it would be unjust and unreasonable and break with 

Commission precedent to allocate to generators the costs of Schedule 10, whether kept as 

a regulation reserve or reformulated to a system non-spin service, while allocating other 

ancillary services costs broadly to load. AWEA states that all users of the grid add 

variability and uncertainty and that all benefit when the grid is better able to 

accommodate variability and uncertainty. AWEA also argues that the capacity used to 

provide Schedule 10 service would be available to provide a number of other ancillary 

services, not to mention to the public utility transmission provider to meet peak demand.

287. Western Grid states that the integration costs of other types of generation are 

largely ignored and the regulation and frequency costs imposed by large loads are 

broadly socialized. Western Grid therefore contends that grid integration costs related to 

VERs should be recovered in a manner comparable to the way grid integration costs 

imposed by large conventional generators are recovered. Argonne National Lab argues 

that calculating the net impact of VERs on regulation service needs is likely to be 

difficult and contentious and that to ensure just and reasonable treatment of all resources, 

the Commission should be careful in imposing specific requirements on VERs without 
Docket No. RM10-11-000 - 204 -

considering the specific impacts on system reliability and operating reserve costs from 

other generating resources as well. Similarly, the Federal Trade Commission 

recommends that the Commission consider whether the costs of imbalance services 

provided to other types of generators can readily be identified and charged to the 

responsible parties. 

288. Some commenters support the proposal to condition the implementation of 

differentiated volumetric rates on whether that transmission provider has implemented 

power production forecasting and intra-hour scheduling reforms.303 AWEA states that 

Schedule 10 should not be charged at all until a transmission provider has fully 

implemented the Efficient Dispatch Toolkit and the Commission’s proposed sub-hourly 

scheduling and variable energy forecasting operating reforms. Clean Line states that 

implementation of forecasting should be required before any special charges are assigned 

to renewable generators. Clean Line argues that, before transmission providers can 

charge a just and reasonable rate to recover ancillary service costs, they must use 

reasonable means to minimize those costs – such as forecasting.

289. Some commenters suggest that differentiated volumetric rates should be 

conditioned on implementation of additional reforms beyond those set forth in the 

 303 E.g., AWEA; BP Energy; Iberdrola; Independent Power Coalition West; 

NextEra; Oregon & New Mexico PUC; Public Interest Organizations; Vestas.
Docket No. RM10-11-000 - 205 -

Proposed Rule.304 For example, Environmental Defense Fund maintains that a public 

utility transmission provider should not be permitted to establish different volumetric 

reserve requirements for VERs unless it has demonstrated to the Commission that the 

balancing authority area is optimally sized or cooperating with other balancing authority 

areas. Oregon & New Mexico PUC similarly state that Schedule 10 charges for VERs 

should be conditioned on a demonstration by the public utility transmission provider 

regarding the measures it has considered to increase cooperation with other balancing 

authorities to lower the cost of integrating wind and solar. First Wind argues that public 

utility transmission providers should only be permitted to charge for generator regulation 

service once they have implemented procedures for dynamic transfers in addition to intrahour scheduling. CESA contends that, before imposing any generator regulation costs on 

VERs, public utility transmission providers should first implement fast intra-hour 

markets and intra-hourly scheduling; a robust ancillary services market; the option for 

third-party or self supply of ancillary services; dynamic transfer capability out of the 

balancing authority area; and Area Control Error (ACE) diversity interchange or an 

energy imbalance service market.

290. In contrast, ELCON asserts that Schedule 10 as proposed is a mechanism for the 

socialization of costs that should be directly assigned to VERs or their customers. Grant 

PUD argues that variable loads and variable resources should be charged differently for 

 304 E.g., Iberdrola; First Wind; Oregon & New Mexico PUC; Environmental 

Defense Fund.
Docket No. RM10-11-000 - 206 -

regulation service according to the nature of the different costs placed on the public 

utility transmission provider. A number of other commenters agree, objecting to any 

delay in cost recovery associated with providing generator regulation service.305 For 

example, Pacific Gas & Electric and Idaho Power argue that public utility transmission 

providers incur costs to provide generator regulation service regardless of whether they 

are employing intra-hourly scheduling and, thus, preventing recovery of generator 

regulation service costs shifts those costs to other customers in violation of cost causation 

principles. 

291. EEI opposes requiring a public utility transmission provider to commit specific 

actions before seeking rate recovery under section 205, particularly when such actions 

violate cost causation principles. EEI states that as articulated by the Commission in 

Northern States Power Company, “[t]he fundamental theory of Commission ratemaking 

is that costs should be recovered in the rates of those customers who utilize the facilities 

and thus cause the cost to be incurred.”306 According to EEI, the D.C. Circuit echoed this 

sentiment in KN Energy, Inc. v. FERC, “[s]imply put, it has been traditionally required 

that all approved rates reflect to some degree the costs actually caused by the customer 

 305 E.g., Tacoma Power; Montana PSC; Pacific Gas & Electric; PNW Parties; NV 

Energy; Public Power Council; Natural Gas; WUTC.

306 EEI at 29 (citing N. States Power Co., 64 FERC ¶ 61,324, at P 13 (1993) 

(emphasis supplied) (citations omitted)). 
Docket No. RM10-11-000 - 207 -

who must pay them.”307 EEI and others state that, to the extent the Commission 

conditions generator regulation service cost recovery on implementing the Proposed 

Rule’s reforms, the Commission should explain how such a limitation does not 

effectively force public utility transmission providers to waive their sections 205 and 206 

rights under the FPA in contravention of Atlantic City Electric Company.

308

292. Southern opposes conditioning public utility transmission providers’ rights to 

recover rates under section 205 of the FPA for generator regulation and frequency 

response service on the implementation of such reforms. Southern argues that utilities 

have a statutory right to establish just and reasonable rates under sections 205 and 206 of 

the FPA. If the Commission pursues these limitations, Southern asks the Commission to 

explain how such a limitation does not effectively force public utility transmission 

providers to waive their section 205 and 206 rights.

 307 EEI at 29 (citing KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 

1992); Alcoa Inc. v. FERC, 564 F.3d 1342, 1346 (D.C. Cir. 2009); Illinois Commerce 

Commission v. FERC, 576 F.3d 470, 476 (7th Cir. 2009); Pub. Serv. Comm. of Wisc. v. 

FERC, 545 F.3d 1058, 1067 (D.C. Cir. 2008); Pac. Gas & Electric Co. v. FERC, 373 

F.3d 1315, 1320 (D.C. Cir. 2004)). 

308 EEI at 27-28 (citing Atlantic City Elec. Co., 295 F.3d 1, 10 (2002) (finding that 

the Commission lacks the authority to require public utility transmission providers to 

cede their rights under section 205 of the FPA); MidAmerican at 26; Puget at 17 

(questioning whether whether requiring one-year of data reporting interferes with a 

public utility transmission provider’s rights under section 205 of the FPA); WUCT at 7 

(questioning whether requiring 15-minute scheduling and one-year of data reporting 

interfere with a public utility transmission provider’s rights under section 205 of the 

FPA)).
Docket No. RM10-11-000 - 208 -

293. LADWP argues that the proposed requirements would place public utility 

transmission providers in a defensive role. LADWP states that presuming a public utility 

transmission provider makes a sufficient showing that it implemented intra-hour 

scheduling and deployed power production forecasting for VERs, a transmission provider 

is further compelled to demonstrate the basis for any difference in regulating reserves 

between VER transmission customers and non-VER transmission customers. LADWP 

argues that this could put the public utility transmission providers in a defensive role of 

justifying the findings and conclusions within a system impact study report, in the event 

performed by the public utility transmission provider.

iii. Power Production Forecasting

294. Some commenters state specific opposition to linking power production 

forecasting to the implementation of differentiated volumetric rates under Schedule 10.309 

Southern argues the Commission would exceed its statutory authority if it required 

implementation of power production forecasting. Southern states 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.”310 

Southern contends that, because the FPA never mentions meteorological forecasting, it is 

 309 E.g., Bonneville Power; Montana PSC; Natural Gas; Public Power Council; 

Puget Sound Energy; NV Energy.

310 Southern (citing Cal. Indep. Sys. Operator Co. v. FERC, 372 F.3d 395, 398 

(D.C. Cir. 2004) (citing Atlantic City Elec. Co. v. FERC, 295 F.3d at 8)).
Docket No. RM10-11-000 - 209 -

beyond the scope of the Commission’s authority. Southern explains that public utilities 

have long engaged in meteorological forecasting for load forecasting and dispatch 

purposes; however, 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.

295. While Bonneville Power acknowledges that centralized power production 

forecasts will facilitate system-wide benefits, Bonneville Power disagrees that such 

forecasts should be a prerequisite to the cost recovery of balancing reserve capacity used 

to provide generator regulation reserve-type services. Bonneville Power believes that 

such a requirement would shift costs to other users of the transmission system that would 

not be otherwise incurred but for the VER generation. Puget believes that requiring 

transmission providers to implement power production forecasting as a precondition to 

Schedule 10 cost recovery inappropriately shifts the costs of integrating VERs from the 

VER to the balancing authority. Southern argues that meteorological forecasting issues 

are business decisions that are best left to the transmission providers and the market. EEI 

states that it is not convinced that the power production forecasting requirements are 

necessary to support requiring a higher volumetric amount of Schedule 10 regulation 

service. According to EEI, the data necessary to substantiate a higher volumetric charge 

can be derived by analyzing the deviation between a VER’s scheduled versus actual 

production. EEI, therefore, claims that requiring a public utility transmission provider to 

implement power production forecasting prior to establishing a higher volumetric rate 

creates a barrier to cost recovery.
Docket No. RM10-11-000 - 210 -

296. Montana PSC notes that the Proposed Rule’s data reporting requirements to 

support power production forecasting would only apply to generators that are 20 MW or 

larger. Montana PSC argues that conditioning differentiation of volumetric rates on the 

implementation of power production forecasting could unduly restrict application of

Schedule 10 generation regulation charges to smaller resources. Montana PSC argues 

that all VERs one MW or greater should be responsible for Schedule 10 services that they 

cause.

297. Other commenters ask the Commission to mandate use of power production 

forecasting by all public utility transmission providers with significant amounts of VERs

instead of relying on the public utility transmission owner’s decision to charge 

differentiated Schedule 10 rates.311 The ISO/RTO Council argues that, while 

transmission providers in areas with low to moderate levels of VER interconnection may 

be able to manage variability on their systems without using power production 

forecasting, areas with larger levels of VERs should be required to adopt power 

production forecasting tools to ensure that conditions affecting generation output can be 

anticipated and managed appropriately. SEIA suggests that each transmission provider 

that provides interconnection to or has interconnections with more than 50 MW of VERs 

should be required to develop a power production methodology to accommodate 

integration of VERs. First Wind contends that power production forecasting should be 

 311 E.g., CPUC; ISO RTO Council; Midwest ISO; SEIA.
Docket No. RM10-11-000 - 211 -

mandatory for public utility transmission providers with five percent of VER resources 

on their system. CPUC asks that the Commission clarify that any public utility 

transmission provider may require power production forecasting if VERs are currently or 

anticipated to become significant.

298. Some commenters support the Commission’s recognition that certain regions may 

not have a need for VER power production forecasting because of a low likelihood of 

VERs development.312 For example, Bonneville Power states that the requirement to 

implement centralized forecasting should not apply if the penetration of VERs is less than 

10 percent of load served. Puget argues that it should not be required to use power 

production forecasting because it only serves one exporting VER in its region.

299. Several commenters provide detailed discussions of the various activities that 

public utility providers should be required to undertake in order to show power 

production forecasting is in use. Public Interest Organizations suggest that the 

Commission require public utility transmission providers to demonstrate that VER power 

production forecasts are incorporated into unit commitment, scheduling, and dispatch 

efforts. Oregon & New Mexico PUC state that at a minimum, a public utility 

transmission provider needs to demonstrate that it has requested meteorological and 

operational data from wind and solar generators and has integrated forecast information 

into control room operations. 

 312 E.g., Bonneville Power; NextEra; PNW Parties.
Docket No. RM10-11-000 - 212 -

300. Some commenters contend that the public utility transmission provider should 

demonstrate that it is using the VER forecast to efficiently and reliably commit and 

dispatch resources. These parties offer various criteria regarding costs, accepted industry 

practices, and performance metrics that should be required of public utility transmission 

providers in order to be deemed compliant with the Final Rule.313 The California PUC 

states that, while it does not recommend that the Commission set specific minimum 

quality standards or cost maximums for VERs forecasts at this time, the Commission 

should monitor results of public utility transmission providers’ assessments. If the 

quality of forecasts varies significantly among public utility transmission providers, the 

Commission may determine that minimum quality standards or maximum cost limits for 

VERs forecasts are necessary to prevent unjust, unreasonable, or unduly discriminatory 

rates. 

301. Other commenters argue that the Commission should ensure that the risks 

associated with inaccurate schedules or resource specific forecasts remain with the 

VER.314 Montana PSC states that the forecasting requirement should be the 

responsibility of VER instead of the public utility transmission provider. NorthWestern 

states that it is inappropriate to make the public utility transmission provider responsible 

for forecasting the VER power output when it is the responsibility of the VER to provide 

 313 E.g., AWEA; California PUC; Iberdrola; NaturEner. 

314 E.g., AEP; Large Public Power Council; Midwest ISO Transmission Owners; 

Montana PSC; NorthWestern.
Docket No. RM10-11-000 - 213 -

its schedule. NorthWestern points out that, if the public utility transmission provider 

provides a forecast of the VER power production, as proposed by the Proposed Rule, and 

the VER submits a different schedule, Control Performance Standard 2 violations may 

occur that would not have occurred if an accurate power production forecast had been 

submitted by the VER. NorthWestern argues that the forecasting requirement would 

place the balancing authority in an unacceptable position if the forecast or power 

production data is inaccurate. Midwest ISO Transmission Owners state that regardless of 

whether the public utility transmission provider requires VERs to provide meteorological 

data or employs other tools in order to increase the effectiveness of scheduling and 

dispatching activities, all generation resources must retain the ultimate responsibility for 

determining their unit’s deliverability; accordingly, variations from scheduled deliveries 

must remain the responsibility of the generating resource, including VERs.

302. Bonneville Power argues that, if the Commission requires centralized power 

production forecasts for public utility transmission providers with significant amounts of 

VERs on their systems that intend to differentiate their Schedule 10 pricing, it is 

preferable that the Commission also require all VERs to schedule according to the 

centralized forecast component for each plant. Puget explains that, if the public utility 

transmission provider’s forecast sets the schedule, then there could be a perverse 

incentive for public utility transmission providers to generate inaccurate forecasts and 

collect larger generator imbalance charges under Schedule 9; however, if the VER is 

permitted to set its own schedule that differs from the public utility transmission 

provider’s forecast, it remains unclear how the public utility transmission provider is 
Docket No. RM10-11-000 - 214 -

supposed to manage and deploy its resources -- according to its own forecast or to the 

VER’s schedule. Puget requests that these questions be clarified before the Commission 

implements a power production forecasting requirement for public utility transmission 

providers, whether as a stand-alone mandate or as a precondition to Schedule 10 cost 

recovery.

303. Invenergy argues that the Final Rule should hold public utility transmission 

providers: (1) accountable for the accuracy of the forecasts that they use to determine 

regulation capacity requirements; and (2) to performance levels that current technology 

supports. Invenergy states that ISOs and RTOs that have implemented centralized wind 

forecasting are generally realizing accuracy rates of 89 percent or greater. Invenergy 

argues that the Final Rule should require the public utility transmission provider to 

provide customers with forecasting performance metrics on a periodic basis and, if 

forecasts do not prove to be reliable, require the public utility transmission provider to 

take immediate steps (including improving its forecasting systems and equipment or 

relinquishing responsibilities to an independent third party) to ensure that future forecasts 

are accurate. 

304. Commenters state that in RTO regions, the RTO would be the more appropriate 

entity to conduct power production forecasting. National Grid asks the Commission to 

clarify who the “transmission providers” are that will undertake the energy forecasting 

responsibility. National Grid states that the role of developing and implementing energy 

forecasting tools is well suited to a centralized entity with existing capabilities in data 

collection, region wide system forecasting and centralized dispatch responsibilities such 
Docket No. RM10-11-000 - 215 -

as RTOs and ISOs. National Grid requests that the Commission clarify that for the 

purposes of its data forecasting Final Rule the term “transmission provider” means the 

ISOs or RTOs in those regions, as this avoids confusion where the term “transmission 

provider” can refer to either the ISO or its members. 

305. Some commenters point out that many regions are currently undertaking their own 

forecasting and data gathering initiatives or programs to integrate VERs, and request that 

the Commission allow for regional flexibility.315 Pacific Gas & Electric requests that 

individual public utility transmission providers be given flexibility on how to implement 

that requirement. Pacific Gas & Electric requests that in its Final Rule the Commission 

provide latitude for the California ISO and other similarly situated transmission providers 

to continue their existing programs to gather the relevant meteorological and operational 

data, and to propose incremental refinements to them, so long as the programs maintained 

by these transmission providers can accomplish the purposes set forth in the Proposed 

Rule for gathering this information. 

iv. One Year Data Requirement

306. Some commenters contend that the proposal to require public utility transmission 

providers to collect power production forecasting data for one year prior to instituting a 

differentiated regulation requirement for VERs violates cost causation principles and 

 315 E.g., Massachusetts DPU; Pacific Gas & Electric; Midwest ISO.
Docket No. RM10-11-000 - 216 -

imposes costs of balancing reserve capacity needed for VERs on other customers.316 

Such commenters maintain that the one-year data collection requirement unreasonably 

delays public utility transmission providers from demonstrating that they are entitled to 

recover different volumetric amounts associated with providing generator regulation 

service from different types of generators.317 Bonneville Power argues that there may be 

sound economic and operational bases for providing or procuring differential quantities 

of incremental and decremental balancing reserve capacity. Western Farmers suggest 

that the Commission allow public utility transmission providers to propose the volumetric 

component of the Schedule 10 charge along with the proposed rates in their initial 

Schedule 10 compliance filing. Natural Gas and Puget similarly argue that public utility

transmission providers should have an opportunity to allocate ancillary service costs as 

soon as they are justifiably able to do so. MidAmerican contends that the one-year data 

collection requirement is inconsistent with the Westar precedent.

307. Some commenters suggest that public utility transmission providers should be 

permitted to establish rates using historical data, subject to adjustment as necessary over 

time.318 For example, Bonneville Power states that rates can be updated as public utility 

 316 E.g., Bonneville Power; Puget; MidAmerican; Southern California Edison; 

Natural Gas.

317 E.g., EEI ; MidAmerican; Puget; WUTC.

318 E.g., Bonneville Power; Southern California Edison; California PUC; EEI; 

NorthWestern.
Docket No. RM10-11-000 - 217 -

transmission providers gain experience with reductions in the need for balancing reserve 

capacity requirements associated with intra-hourly scheduling, centralized forecasting 

and any other initiatives. Similarly, Puget suggests that reductions in the VERs 

volumetric component could be incorporated into a subsequent rate filing after 

implementation of 15-minute scheduling and power production forecasting by the utility. 

NorthWestern suggests that, just as the Commission routinely allows a proposed rate to 

take effect on an interim basis subject to refund until final approval is received, the 

Commission likewise should consider applying a similar principle in allowing interim 

regulating service cost recovery. Pacific Gas & Electric proposes that until one year’s 

worth of data are available, public utility transmission providers should be able to use 

simulated data to estimate the relative contribution of load, imports, VERs and other 

generation for the overall need for generator regulation reserves.

308. In contrast, Vestas argues that public utility transmission providers should be 

required to implement the two operational changes immediately and then collect data 

over at least the next 12 months regarding the levels of schedule deviations on their 

systems for all types of generation. According to Vestas, the Commission should require 

the submission of that data to the Commission and take comments from interested market 

participants on the appropriate rate mechanism to permit the recovery of any costs 

incurred to address remaining variations between generator schedules and generator 

output. 

309. Organization of Midwest ISO States asks the Commission to require public utility 

transmission providers with significant VER capacity, such as three percent or more of 
Docket No. RM10-11-000 - 218 -

total capacity, to submit statistical data on the variability of generation across the 

different types of generation resources and load. If there is a significant difference 

between types of resources, Organization of Midwest ISO States contends that the public 

utility transmission provider should be required to allocate the costs of increased 

regulation and other ancillary services developed in the future to the generation resources 

causing those costs.

v. Other

310. Some commenters express concern about the static nature of the rates and volumes 

in Schedule 10.319 SEIA argues that public utility transmission providers who have 

selected a methodology and begun to apply different Schedule 10 rates for different 

categories of customers should be required to revisit their forecasting methodologies and 

rates on a regular basis. RenewElec notes that data collected over a one-year period that 

may feature anomalies (e.g., wind droughts). RenewElec suggests that the Commission 

require transmission providers to retain data provided under the new pro forma LGIA 

Article 8.4 for at least 10 years and commit to performing annual follow-up studies over a 

period of not less than five years that update power production forecasts with new data 

received. RenewElec suggests that the Commission include a biannual re-opener 

provision for VER-specific Schedule 10 charges, or through other review and 

implementation combinations.

 319 E.g., SEIA, RenewElec, NaturEner.
Docket No. RM10-11-000 - 219 -

311. NaturEner asserts that an annual re-evaluation of the integration charge needs to 

be undertaken to take into account the impact of increased diversity, improved 

operations, market innovations and other changed circumstances, as well as to correct any 

inaccuracy in the original (or immediately prior) assessment. NaturEner also requests 

clarification regarding whether a VER transmission customer could be required to pay a 

VER integration charge in arrears if a public utility transmission provider is subsequently 

permitted to levy the charge.

312. Some commenters oppose the Commission’s proposal to group resources together 

for the purpose of allocating Schedule 10 volumes.320 For example, BrightSource states 

that assigning all VERs the same regulation requirement could distort the incentives 

created by the cost allocation if they are evaluated as a single, undifferentiated class. 

First Wind asserts that the rate should be designed to recognize the actual variability of 

output of the resource paying the rate because two wind generation projects of the same 

installed capacity and energy production might have different levels of variability due to 

factors such as local differences in the variability of the “wind resource” (the relative 

wind generating value of the location); the number, size, and manufacturer of the wind 

turbines; and differences in distances between wind turbines. RenewElec offers that high 

capacity wind generation units have a disproportionally smaller impact on variability than 

lower capacity units. According to AWEA, the variability of resources within a category 

 320 E.g., BrightSource; FirstWind; RenewElec; AWEA.
Docket No. RM10-11-000 - 220 -

cancels each other out to the benefit of those resources in that category, imposing a 

disadvantage on customers that are grouped in smaller categories.

313. Snohomish County PUD questions whether it is appropriate to apportion any 

volume of generator regulation reserves to behind-the-meter generation. Snohomish 

County PUD contends that variations in output from the behind-the-meter generator are, 

from the perspective of the public utility transmission provider, indistinguishable from 

variations in the distribution utility’s load. Accordingly, Snohomish County PUD asks 

the Commission to clarify that behind-the-meter generators–those that are interconnected 

directly to and consumed by the load of the local distribution utility rather than a 

transmission utility–will not be required to purchase generator balancing capacity from 

the public utility transmission provider in the absence of a voluntary agreement between 

the public utility transmission provider and the generator to install appropriate metering 

that measures the variability of the generator and to pay the Schedule 10 charges justified 

by that variation.

314. Several commenters suggest that the Commission convene a technical conference 

or require other processes to determine the appropriate per-unit and volumetric rates

under the proposed Schedule 10.321 AWEA states that a technical conference would be 

appropriate to establish consistent principles for determining the methodology that should 

be used for calculating and allocating Schedule 10 costs. Some commenters request that 

 321 E.g., AWEA; BrightSource; EPSA; SEIA.
Docket No. RM10-11-000 - 221 -

the Commission require stakeholder involvement in connection with the development of 

Schedule 10 volumes.322 For example, First Wind requests that the Commission require 

RTOs to conduct a robust and transparent stakeholder process which attempts to reach 

consensus prior to them making an allocation filing, and that non-RTO public utility 

transmission providers conduct public workshops prior to any allocation filing.

b. Commission Determination

315. For the reasons discussed above, the Commission is not implementing a generic 

Schedule 10 to the pro forma OATT for generator regulation service. Instead, the 

Commission takes this opportunity to respond to the individual commenter concerns 

regarding the proper design of a generator regulation service charge in order to provide 

guidance in the development of proposals for such services.

316. In response to the Large Public Power Council and Puget, those public utility 

transmission providers that choose to propose a rate schedule for generator regulation 

service may include opportunity costs for generator regulation service in certain 

circumstances. Such resources are often dispatched in the middle of their operating range 

to allow the generator to provide regulation-up as well as regulation-down and as a result 

forego other opportunities. Not to allow compensation would create a barrier to the 

provision of services by frustrating the recovery of legitimate costs. 

 322 E.g., California PUC; First Wind; SEIA.
Docket No. RM10-11-000 - 222 -

317. A number of commenters question the appropriate design of the volumetric 

component of Schedule 10 rates, i.e., the component in the Proposed Rule that allowed 

public utility transmission providers to require different transmission customers (or 

generator classes) to purchase or otherwise account for different quantities of regulation 

reserves based on cost causation principles. The Commission agrees that calculating the 

relative impact of individual customers or customer classes on a public utility 

transmission provider’s overall generation regulating reserve needs and allocating those 

costs accordingly can be a difficult and complex determination. However, the 

Commission believes that the complexity of these proceedings can be mitigated where 

entities take note of, and incorporate, the following principles. 

318. First, public utility transmission providers seeking to distinguish customers into 

classes for the purpose of requiring them to purchase or otherwise account for different 

quantities of generation regulating reserves should do so only to the extent such classes 

and distinctions among classes are reasonably related to operational similarities and 

differences among those resources.323 

319. Second, to the extent a public utility transmission provider proposes to break 

customers into specific groups based on operational characteristics, we expect public 

utility transmission providers to provide detailed explanations as to why such 

classifications are appropriate if and when they propose to allocate different generating 

 323 See Westar, 137 FERC ¶ 61,142 at PP 27-28.
Docket No. RM10-11-000 - 223 -

regulation reserve obligations to different customer classes. The Commission has 

required that overall generator regulation requirements be established by taking diversity 

benefits into account. Diversity benefits result from aggregating the variations of all 

resources so that one resource’s negative deviation can offset some or all of another 

resource’s positive deviation. When the transactions of two customers result in diversity 

benefits, it is incorrect to say that one customer is benefitting the other but not vice versa. 

Instead, the diversity benefits result from both transactions and sharing of these benefits 

among the customers is reasonable. In Westar, the Commission found that this portfoliowide approach to assessing generator regulation charges appropriately shares diversity 

benefits among generators and load.324 Ultimately, this concept will need to be 

reconciled with any customer classifications proposed by the public utility transmission 

provider in a way that prevents any over-recovery of these capacity costs.

320. Third, to the extent a public utility transmission provider proposes to differentiate 

among customers (or customer classes) in determining their relative regulating reserve 

responsibilities, the public utility transmission provider must demonstrate that the overall 

quantity of regulating reserve it requires of its transmission customers accounts for 

diversity benefits among all resources and loads, and the allocations to individual 

customers (or customer classes) of their proportionate share is based on the operational 

characteristics of such customers (or customer classes). 

 324 See Westar, 130 FERC ¶ 61,215 at PP 37-38.
Docket No. RM10-11-000 - 224 -

321. Fourth, weather events such as droughts may affect the required quantity of 

generator regulating reserves that the public utility transmission provider must have in 

reserve more or less during one portion of the year versus another portion of the year. In 

such cases, these diversity events, though perhaps characterized as anomalies, should be 

included in the data set so that the quantity and costs of such reserves are more reflective 

of actual system operations.

322. Fifth, there is a relationship between the use of intra-hour scheduling by 

transmission customers and the quantity of reserves needed to provide Schedule 9 

generator imbalance service. In other sections of this Final Rule, the Commission 

requires all public utility transmission providers to offer transmission customers the 

option of using more frequent transmission scheduling intervals within each operating 

hour, at 15-minute intervals, noting that over time public utility transmission providers 

will be able to rely more on planned scheduling and dispatch procedures and less on 

reserves to maintain overall system balance. In the Proposed Rule, the Commission 

sought comment on whether to condition the ability of public utility transmission 

providers to require different transmission customers to purchase or otherwise account 

for different quantities of generator regulating reserves on the implementation of intrahour scheduling reforms. Given that such reforms are mandated in this Final Rule, the 

Commission concludes that condition to be satisfied.325 In designing any proposals for 

 325 See supra IV.A.1 (Intra-Hour Scheduling Requirement).
Docket No. RM10-11-000 - 225 -

generator regulation service charges, a public utility transmission provider should 

consider the extent to which transmission customers are using intra-hour scheduling in 

evaluating whether to require different transmission customers to purchase or otherwise 

account for different quantities of generator regulating reserves. 

323. Sixth, there also is a relationship between the use of power production forecasting 

and the allocation of generator regulation reserve quantities to a particular class of 

customers. The record in this proceeding demonstrates that the quantity of reserves used 

to provide generator regulation service can be most efficiently managed with the 

implementation of power production forecasting (as well as intra-hour scheduling) by 

public utility transmission providers. While commenters disagree on the extent to which 

power production forecasting may affect reserve commitments, the Commission finds 

that 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 services, such as regulation reserve. Without the increased 

situational awareness of projected variability provided by power production forecasts, the 

public utility transmission provider’s ability to commit or de-commit resources providing 

regulation reserves efficiently can be constrained. This lack of situational awareness 

potentially can result in rates for generator regulation service that are unjust and 

unreasonable or unduly discriminatory. 

324. We recognize that conditioning the allocation of different quantities of regulation 

reserves to different transmission customers on the public utility transmission provider 
Docket No. RM10-11-000 - 226 -

developing and deploying power production forecasting is contentious. On one hand 

certain public utility transmission providers believe that they should either be able to use 

historical data or make other approximations to establish the quantity of regulation 

reserves to be required of a given transmission customer or class of customers. On the 

other hand, transmission customers that are VERs contend that the Commission has not 

gone far enough and that additional reforms are necessary to ensure that VERs do not 

disproportionately bear the burden of the cost of regulating reserves. The Commission 

believes that public utility transmission providers need an effective opportunity to file for 

cost recovery, while VERs need assurance that they are not unduly assigned costs.

325. Accordingly, while the Commission reserves judgment as to the appropriate power 

production forecasting requirements for a particular public utility transmission provider, 

we expect that the implementation of power production forecasting will be addressed in 

any proposal to require different transmission customers to purchase or otherwise account 

for different quantities of generator regulating reserves. For example, a public utility 

transmission provider could demonstrate that it is utilizing power production forecasts (or 

other comparable technique) to manage system operating costs and/or to improve 

reliability by enabling the more efficient commitment and dispatch of resources. The 

Commission agrees with the California PUC that, as part of such a demonstration, the 

public utility transmission provider should explain how the data required from VERs are 

incorporated into the power production forecast and how the resulting forecast is used to 

support the management of operating costs and/or reserves or otherwise ensure that 

capacity costs incurred to provide Schedule 9 service are prudently incurred.
Docket No. RM10-11-000 - 227 -

326. The Commission declines to require the additional forecasting-related showings 

suggested by NaturEner and others. The technologies and techniques for power 

production forecasting are still being refined and may differ from region to region. While 

the recommendations made by AWEA, Iberdrola, and NaturEner may be appropriate 

benchmarks for power production forecasts utilizing today’s technology, the Commission 

believes that pre-defining these additional criteria would not provide the flexibility 

needed for public utility transmission providers to adopt new forecasting techniques or 

technologies as they are developed. The Commission also declines to adopt the further 

recommendations of the California PUC and others to include monitoring and reporting 

requirements for public utility transmission providers that engage in power production 

forecasting. The Commission finds adopting these requirements to be unnecessary at this 

time.

327. However, the Commission agrees with Iberdrola and others that the public utility 

transmission provider should make the results of any centralized forecast used by the 

public utility transmission provider available through a secure information exchange to 

VER generators providing related data. The Commission believes that the VERs should 

be able to access the results of the public utility transmission provider’s forecast in order 

to ensure that the forecasting service is producing accurate results. Thus, public utility 

transmission providers proposing to require different transmission customers to purchase 

or otherwise account for different quantities of generator regulating reserves should 

explain in their proposals how forecasting results will be shared.
Docket No. RM10-11-000 - 228 -

328. In response to comments regarding forecasting risk, the Commission clarifies that 

the transmission customer is responsible for the accuracy of transmission schedules and 

the public utility transmission provider is responsible for the reliability of its system. 

Therefore, the public utility transmission provider would utilize the power production 

forecast to identify the necessary amount of reserves and to use those reserves to maintain 

reliability of the transmission system. The obligation of the transmission customer is to 

submit schedules for deliveries. Power production forecasting is intended to inform the 

transmission provider regarding aggregate system variability that results from having 

VERs on its system, not to replace transmission schedules from transmission customers 

delivering from VERs. Public utility transmission providers using power production 

forecasts should do so to manage uncertainty in the same manner they use other forecasts 

of uncertainty for the transmission system. For example, despite service agreements to 

serve load, public utility transmission providers develop and use load forecasts to assure 

load can be met reliably and efficiently. Similarly, despite transmission schedules to 

deliver from a VER, public utility transmission providers should use power production 

forecasts to assure energy can be provided to load in a reliable and efficient manner. 

329. Therefore, the Commission agrees with NorthWestern and others that the 

transmission customer maintains responsibility for the accuracy of its transmission 

schedule. However, we disagree with NorthWestern’s interpretation concerning NERC 

Control Performance Standard 2 violations. A public utility transmission provider is not 

responsible for submitting a transmission schedule on behalf of a VER. As explained 

above, power production forecasting would be utilized to identify and acquire the 
Docket No. RM10-11-000 - 229 -

appropriate amount of reserves needed to integrate VERs reliably. Nothing in this Final 

Rule alleviates the public utility transmission provider’s obligations under NERC 

Reliability Standards. 

330. The Commission declines to require transmission customers delivering from a 

VER to submit transmission schedules according to the public utility transmission 

provider’s forecast, as suggested by Bonneville Power. While the public utility 

transmission provider is able to forecast the aggregate variability of the system with 

greater accuracy through centralized power production forecasting, the individual VER 

may be better able to produce the most accurate schedule for its particular facility. 

Requiring a transmission customer to submit transmission schedules for VER deliveries 

according to a centralized forecast would cloud the delineation between the obligations of 

the VER and the obligations of the public utility transmission provider with respect to the 

provision of transmission service. 

331. The Commission disagrees with Puget’s example, and clarifies that the public 

utility transmission provider’s obligation should be to deploy its resources according to 

its own forecast in order to maintain the reliability of the system. The public utility 

transmission provider retains the risk and responsibility for inaccurate procurement of 

reserve requirements while the transmission customer retains the financial risk and 

responsibility for inaccurate schedules. The Commission finds that the incentive to avoid 

Schedule 9 generator imbalance penalties and any relevant charges for generator 

regulation service provides sufficient incentive for VERs to submit an accurate schedule.
Docket No. RM10-11-000 - 230 -

332. The Commission agrees with National Grid and others that, as the entity providing 

transmission service under an OATT, the ISO or RTO would engage in power production 

forecasting within its region. In response to Pacific Gas & Electric and others requesting 

flexibility to implement power production forecasting, the Commission finds that the 

guidance provided affords sufficient flexibility to allow public utility transmission 

providers to tailor their forecasting programs to meet their needs, whether for the purpose 

of developing proposals for generator regulation charges or otherwise. 

333. The Commission emphasizes that the foregoing discussion is intended to provide a 

framework to assist public utility transmission providers in developing proposals for 

generator regulation service should they desire to do so. The Commission does not 

intend this guidance to preclude a public utility transmission provider from making an 

alternative proposal under section 205 of the FPA. However, it does provide guidance to 

public utility transmission providers regarding the facts and circumstances that the 

Commission may find relevant in evaluating such proposals.

334. A number of commenters challenged the Commission’s proposal to condition 

proposals that require different transmission customers to purchase or otherwise account 

for different quantities of generator regulating reserves on performance of the activities 

discussed above. These arguments have largely been rendered moot by the 

Commission’s decision not to adopt the Proposed Rule in that regard. Even as applied to 

the guidance provided above, the Commission disagrees that a future decision by the 

Commission to condition proposals that require different transmission customers to 

purchase or otherwise account for different quantities of generator regulating reserves on 
Docket No. RM10-11-000 - 231 -

the performance of certain actions would violate cost causation principles or otherwise 

would preclude public utility transmission providers from recovering prudently incurred 

costs. In reviewing any future proposal to allocate a greater quantity of capacity costs to 

a particular set of transmission customers, it would be reasonable for the Commission to 

consider whether the public utility transmission provider has taken steps to mitigate such 

costs. This does not mean, as some commenters imply, that the public utility 

transmission provider has no other means to recover its costs. The public utility 

transmission provider could continue to rely on existing rate mechanisms to recover 

reserve costs or may propose to require a uniform quantity of generation regulating 

reserves from all transmission customers that is commensurate with transmission 

customers’ proportionate effect on net system variability and taking diversity benefits 

into account.

335. The Commission agrees with commenters that implementing other reforms, such 

as consolidating balancing authority areas or implementing an ancillary services market, 

may be beneficial to the reliable and efficient integration of VERs. However, the 

Commission is not persuaded that these additional reforms are a necessary precondition 

to proposals that require different transmission customers to purchase or otherwise 

account for different quantities of generator regulating reserves. As noted in the 

Proposed Rule, many of these additional reforms are being discussed in other forums. 

The Commission will continue to monitor these proposals as they develop and modify 

our approach to this issue as appropriate as conditions develop.
Docket No. RM10-11-000 - 232 -

3. Use of Contingency Reserves

a. Commission Proposal

336. In the Proposed Rule, the Commission sought comments from NERC and industry 

stakeholders on the steps needed to resolve confusion regarding the use of contingency 

reserves to manage extreme ramp events of VERs.326 The Commission also sought 

comments from NERC and industry stakeholders on the extent to which some additional 

type of contingency reserve service (beyond the services provided under Schedule 5 and 

6 of the pro forma OATT) would ensure that VERs are integrated into the interstate 

transmission system in a non-discriminatory manner while remaining consistent with 

NERC Reliability Standards.327

b. Comments

337. NERC indicates that large wind ramping events are similar to conventional 

generator contingency events in that they are large and relatively infrequent, yet they 

differ in that wind ramps are much slower than instantaneous contingency events and 

may be possible to forecast. NERC states that the use of contingency reserves to address 

wind ramps is similar to what is used to address large, relatively infrequent wind ramps 

 326 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 100 (citing Schedule 5 

(Operating Reserve – Spinning Reserve Service) and Schedule 6 (Operating Reserve –

Supplemental Reserve Service) respond to contingency events. Spinning Reserve 

Service is used to serve load “immediately in the event of a system contingency” whereas 

Supplemental Reserve Service “is not available immediately to serve load but rather 

within a short period of time.”)).

327 Id. P 100.
Docket No. RM10-11-000 - 233 -

because contingency reserves are seldom deployed, yet long ramp durations can make it 

difficult to include wind ramps as actual contingencies. NERC explains that Resource 

and Demand Balancing (BAL) Reliability Standard BAL-002 (Disturbance Control 

Performance) requires ACE to be restored 15 minutes following the disturbance (R4) and 

the contingency reserves to be restored within 105 minutes (90 minutes after the 15 

minute disturbance recovery period – R6). NERC states that both of these requirements 

can be problematic for wind ramps because they can be longer than the disturbance 

recovery period as well as the reserve restoration period. 

338. Still, NERC indicates that it may be appropriate to use contingency reserves in 

response to a portion of a wind ramp. NERC states that shared contingency reserves 

could be used to initiate the response, allowing time for alternate supply (or load 

reduction) to be implemented. NERC suggests that the industry consider developing 

rules governing reserve deployment and restoration, similar to those that currently 

address conventional contingencies.

339. Other commenters express openness to using contingency reserves for wind 

events.328 Commenters indicate that there are discussions in the Northwest Power Pool 

(NWPP) about the use of contingency reserves for wind events.329 AWEA contends that 

contingency reserves should be used for the initial period of an extreme wind ramp 

 328 E.g., Powerex; NaturEner; California PUC; MidAmerican.

329 E.g., Powerex; Tacoma Power.
Docket No. RM10-11-000 - 234 -

because both contingency events and extreme wind ramp events are very infrequent, and 

therefore, the use of contingency reserves for extreme wind ramp events would be highly 

unlikely to coincide with a need to use those reserves for a conventional generator’s 

contingency event. NextEra urges the Commission to convene a technical conference to 

address how to deploy contingency reserves to address ramp events in a manner that will 

promote reliability. 

340. Xcel indicates that there is confusion regarding the use of contingency reserves to 

manage extreme ramping events. Xcel states that the confusion arises as entities attempt 

to define the allowable triggering events for the activation of contingency reserves. Xcel 

recommends that the standard for contingency reserve activation include disturbances 

related to less-than-anticipated VER (e.g., wind) production, sudden drop-off of VER 

production, or associated ramp limitations on balancing resources due to forecast errors. 

Xcel contends that ramp events related to VERs are not necessarily caused by the sudden 

failure of generation, but instead may be due to an incorrect wind forecast or limited 

dispatchable generation response. For these reasons, Xcel recommends: (1) expanding 

the definition of disturbances to include ramp events which may occur over a half-hour 

time frame; (2) including a measurement technique related to a ramp event in BAL-002; 

(3) identifying a specific restoration period in BAL-002 (e.g., 45 minutes) related to 

contingency reserves that were deployed for ramping events; and (4) identifying 

compliance metrics and other issues related to deployment of contingency reserves for 

ramp-limited events. Xcel recommends that the Commission request that NERC begin a 
Docket No. RM10-11-000 - 235 -

standards drafting process to consider revisions to the existing BAL-002 standard to 

address the issues discussed by Xcel.

341. Other commenters express reservations with using contingency reserves in 

response to wind events is an improper use of contingency reserves.330 Duke indicates to 

the extent that there is a need for a new service to address VER ramp rates, a new rate 

schedule should be developed for such a service. Pacific Gas & Electric states that there 

may be a need for new integration services to incorporate VERs into the reliable 

operation of the grid. Pacific Gas & Electric submits that various industry activities are 

already underway to consider these issues, and the Final Rule should endorse their 

continued efforts.

c. Commission Determination

342. Based on comments received, the Commission concludes that the issues related to 

the appropriate use of contingency reserves under NERC Reliability Standards need 

further study and vetting before any action is considered. Indeed, comments range from 

expressing confusion over what would constitute an extreme VER event to asking the 

Commission to define “ramp” with some specificity. Rather than opining on any of the 

comments and risk providing guidance without the benefit of more information, the 

Commission finds that the better course of action is to allow industry to continue its work 

and direct our staff to monitor those efforts and engage industry as appropriate. 

 330 E.g., Tacoma Power; ENBALA; Grant PUD; California ISO; Duke; Pacific 

Gas & Electric.
Docket No. RM10-11-000 - 236 -

V. Other Issues

1. Regulatory Text

a. Commission Proposal

343. As part of the Proposed Rule, the Commission sought comment on a minor 

revision to 18 C.F.R. 35.28. To date, when amending its regulations concerning the open 

access requirements of the pro forma OATT, the Commission has listed by name 

Commission rulemaking proceedings promulgating and amending the pro forma OATT 

when explaining the details of a public utility transmission provider’s obligation to have 

an OATT on file with the Commission. The Commission proposed to no longer explicitly 

reference, by name, prior Commission rulemaking proceedings promulgating and 

amending the pro forma OATT in its regulations. Likewise, the Proposed Rule included 

a similar change with respect to a public utility transmission provider’s obligation to have 

standard generator interconnection procedures and agreements and standard small 

generator interconnection procedures and agreements on file with the Commission.331

b. Comments

344. No comments were received on this aspect of the Proposed Rule.

c. Commission Determination

345. The Commission adopts its proposed minor revision to 18 C.F.R. 35.28. We find 

that the existing process for amending regulations concerning the pro forma OATT, 

which necessitates listing by name Commission rulemaking proceedings promulgating 

 331 Proposed Rule, FERC Stats. & Regs. ¶ 32,664 at P 12 & n.29.
Docket No. RM10-11-000 - 237 -

and amending the pro forma OATT when explaining the details of a public utility 

transmission provider’s obligation to have an OATT on file with the Commission, is 

increasingly cumbersome and provides little, if any, benefit. Thus, the Commission will 

no longer explicitly reference, by name, prior Commission rulemaking proceedings 

promulgating and amending the pro forma OATT in its regulations. Likewise, the Final 

Rule adopts a similar change with respect to a public utility transmission provider’s 

obligation to have standard generator interconnection procedures and agreements and 

standard small generator interconnection procedures and agreements on file with the 

Commission.

2. Market Mechanisms

a. Comments

346. Several commenters ask the Commission to revise specific RTO and ISO market 

rules not at issue in the Proposed Rule, while other commenters seek to have the 

Commission address additional market mechanisms for the non-RTO and ISO areas. For 

example, Environmental Defense Fund states that the Proposed Rule does not reform the 

day-ahead market to increase VER participation and decrease the amount of costly outof-market commitments, leading to unjust and unreasonable rates, and undue 

discrimination against VERs. In addition, ACSF asserts that scheduling in the day-ahead 

market and in the unit commitment process should be reformed. ACSF states that the 

technology that makes 15-minute schedules feasible in the spot market also makes 

reforms possible in these other areas. According to ACSF, it is important to prevent the 
Docket No. RM10-11-000 - 238 -

least clean and efficient generation from dominating dispatch at all hours, especially in 

the unit commitment process.

347. Environmental Defense Fund further states that because VERs are only permitted 

to bid a portion of their capacity into the market, they generally receive a lower price. 

According to Environmental Defense Fund, many capacity markets require bidders to 

also participate in the day-ahead market, which most VERs do not do because of the 

financial risk associated with failing to meet day-ahead obligations. Thus, Environmental 

Defense Fund argues that the Commission must consider the available options to 

facilitate VER participation in capacity markets.

348. With regard to non-RTO regions, EPSA states that the Proposed Rule does not 

sufficiently address the lack of market mechanisms available in non-RTO regions to 

conventional generation resources, which have the ability to contribute to VERs 

integration. EPSA suggests that possible market mechanisms and other competitive 

options for integrating VERs in the non-RTO regions should be considered as part of the 

technical conference that EPSA has requested. Similarly, Independent Power Producers 

Coalition–West states that without an organized ISO or RTO market, public utilities must 

face regulatory pressure to advance their integration of VERs and sharing of data, 

otherwise the utilities have little incentive to move toward better integration between 

transmission providers and balancing authorities. Independent Power Producers 

Coalition–West contends that the lack of a competitive ancillary services market that 

would allow independent power producers the opportunity to provide generator 

imbalance services in WECC results in unjust and unreasonable rates.
Docket No. RM10-11-000 - 239 -

349. Tres Amigas contends that Order Nos. 888 and 890 have left little room for a 

market to develop balancing services outside of an ISO/RTO, because the primary 

provider of these services, the balancing authority, has to acquire the capability to 

provide the ancillary services on behalf of all its transmission customers and then sell the 

services at cost-based rates. Tres Amigas states that the Commission should have a twofold objective: (1) determining how market forces can identify and competitively price 

the resources that will be used by balancing authorities for balancing; and (2) establishing 

appropriate mechanisms for allocating the costs incurred by balancing authorities to 

acquire these resources in the marketplace. Further, Tres Amigas asserts that the 

Commission should grant market-based rates to new entrants in order to promote 

formation of a vibrant market for balancing services that includes participation by new 

technologies. Tres Amigas states that the balancing authorities should then file proposals 

to allocate the costs incurred to balance the system among load and generation (including 

generation within the control area that is scheduled to another control area). According 

to Tres Amigas, these cost allocation proposals should take into account the extent to 

which different market participants contribute to the costs of acquiring balancing services 

and benefit from such services.

350. Recycled Energy urges the Commission to consider implementing various 

payments designed to compensate efficient gas generators and combined heat and power 

facilities for the flexibility they provide to utilities. In addition, Recycled Energy asserts 

that the Commission could improve the grid’s reliability and efficiency by encouraging 

the placement of distributed generators in ways that reduce line losses and obtain 
Docket No. RM10-11-000 - 240 -

ancillary benefits. Similarly, Business Council asserts that the OATT should be revised 

to ensure that flexible resources (such as natural gas and pumped storage facilities) are 

better able to provide their services to system operators who integrate VERs, and that 

these services are properly valued. Business Council explains that flexible generation 

resources should be given more opportunities to sell their balancing services to 

transmission providers and should be paid a just and reasonable rate for these services. 

Business Council argues that if the Commission adopts a universal requirement for 15-

minute scheduling, it should make clear that generators should be able to supply 

balancing services on the same 15-minute (or less) basis.

b. Commission Determination

351. The pro forma OATT terms and conditions of service create the platform by 

which the public utility transmission provider makes available non-discriminatory open, 

access transmission service. Since the issuance of Order No. 888, the Commission has 

taken numerous actions to ensure that the principles enunciated in that rule continue to 

remain true, allowing all types of resources – existing and new – access to the grid for the 

benefit of developing competitive markets. In response to commenters like Independent 

Power Producers-West, EPSA and Tres Amigas who assert that the Commission should 

take various steps to establish a competitive ancillary services market or other market 

mechanisms, we believe that the reforms in this Final Rule continue to facilitate the 

development of competitive markets without imposing any particular type of structure for 

doing so. The Commission allows third party sellers to make sales of ancillary services 

at market-based rates, requires all public utility transmission providers to offer open 
Docket No. RM10-11-000 - 241 -

access transmission service and undertake open and transparent transmission planning, 

and allows transmission customers to self-supply their own ancillary services. The 

Commission has long-standing precedent on cost allocation and has long supported 

reserve sharing and power pooling arrangements. Nothing in this rule is intended to 

prevent or create a barrier to the further development of competitive markets. Indeed, we 

think that the reforms adopted herein should help to facilitate the further development of 

competitive markets by allowing transmission customers to tailor their transmission 

schedules and, in turn, better manage generator imbalance and ancillary services costs. 

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.

352. For similar reasons we decline the request from Recycled Energy and Business 

Council to expand the scope of this rulemaking proceeding to include additional 

payments to flexible generation. Both commenters urge the Commission to adopt 

mechanisms that would increase payments to flexible generation resources, such as highefficiency natural gas facilities, so as to properly value the flexibility they provide to 

transmission providers. The Commission has already addressed, in the context of the 

organized markets, compensation for resources providing frequency regulation and is 
Docket No. RM10-11-000 - 242 -

currently exploring a similar issue in bilateral markets outside of RTOs and ISOs.332 In 

this proceeding, the Commission is primarily concerned with providing reforms that will 

provide public utility transmission providers with greater awareness of the variability 

experienced on their systems, as well as providing transmission customers with a tool to 

manage imbalances from schedules by providing for 15-minute adjustments to schedules. 

How these public utility transmission providers choose to provide this service is beyond 

the scope of this inquiry. 

353. With regard to commenters that request additional changes to the RTO and ISO 

day-ahead and capacity markets to facilitate VER integration, we fail to see the direct 

connection between the specific reforms of the Commission’s Proposed Rule and the 

reforms requested. Commenters did not establish that connection and failed to 

demonstrate that the Commission’s proposed reforms are unjust and unreasonable 

without the additional requested reforms. Instead, these commenters merely asked that 

the Commission extend the scope of the rule. As such, we find that commenters’ 

requests that we require additional reforms to RTO/ISO day-ahead, residual unit 

commitment, and capacity market rules are beyond the scope of this proceeding. 

 332 See Frequency Regulation Compensation in the Organized Wholesale Power 

Markets, Order No. 755, 76 FR 67260 (Oct. 31, 2011), FERC Stats. & Regs. ¶ 31,324 

(2011); Third-Party Provision of Ancillary Services; Accounting and Financial 

Reporting for New Electric Storage Technologies, 139 FERC ¶ 61,245 (NOPR).
Docket No. RM10-11-000 - 243 -

354. Finally, we cannot allow sales of energy or capacity at unchecked rates, even by 

new entrants, as suggested by Tres Amigas.333 As noted above, the Commission allows 

for sales at market-based rates upon a showing of lack of market power and is in the 

process of considering ways to streamline the market-based rate showing for certain 

ancillary services.334 

c. Pipeline Transportation Nomination Procedures

i. Comments

355. Some commenters assert that if the Commission requires transmission providers to 

allow intra-hour transmission scheduling to accommodate VERs, the Commission must 

also consider the impact of such requirements on the operation of natural-gas-fired 

electric generation units, and the concomitant need to modify pipeline transportation 

service nomination procedures to calibrate gas transportation and usage more closely 

with the operation of natural gas-fired electric generation units to support VERs.335 

Specifically, APPA contends that despite access to real-time electronic metering and flow 

control and technological advances that enable the electronic submission of gas 

nominations, the current time period used to process pipeline transportation service 

 333See Market-Based Rates For Wholesale Sales Of Electric Energy, Capacity And 

Ancillary Services By Public Utilities, Order No. 697, 72 FR 39904 (July 20, 2007), 

FERC Stats. & Regs. ¶ 61,295, at P 320 (2007).

334 See Third-Party Provision of Ancillary Services; Accounting and Financial 

Reporting for New Electric Storage Technologies, 139 FERC ¶ 61,245 (NOPR).

335 E.g., Joint Parties; TVA; Midwest Energy; APPA.
Docket No. RM10-11-000 - 244 -

nominations and to schedule natural gas is the same time period (up to 4 hours) that was 

adopted over a decade and a half ago. APPA notes that this already substantial 

disconnect between the nomination and scheduling procedures used in the natural gas and 

electric power industries will only become more severe if intra-hour scheduling is 

adopted. Similarly, Joint Parties request that the Commission open a companion docket 

to examine barriers that may exist in the natural gas industry that inhibit the timely access 

to natural gas that is needed to ensure the seamless integration of VERs.336 

356. American Gas and INGAA state that gas transmission systems have developed 

innovative services to accommodate the needs of gas-fired generators to access gas 

supplies quickly in response to electric system dispatch orders. American Gas and 

INGAA explain that these offerings demonstrate that individual, tailored solutions may 

better address gas-electric coordination concerns than a modification of the gas 

nomination schedule. For this reason, American Gas encourages the Commission to 

continue to be open to creative market solutions to meet the needs of gas-fired generators 

in ways that do not unnecessarily affect existing shippers in adverse ways. American Gas 

also encourages the Commission to hold a technical conference or other non-NAESB 

forum to discuss ways in which the natural gas and electric industries can work together.

 336 TVA contends that the Commission should reevaluate its policy of not allowing 

a firm gas transportation holder to take precedence over (i.e., bump) a non-firm customer, 

because gas-fired generators paying for firm gas transportation service must be able to 

support electric needs in general and in integrating VERs specifically. 
Docket No. RM10-11-000 - 245 -

357. American Gas further contends that the Commission’s consideration of gaselectric coordination issues should not focus narrowly on the gas nomination and 

scheduling cycle as a primary solution to the reliability issues which both industries face. 

While American Gas believes that a single, nationwide gas nomination schedule is 

essential to the efficient functioning of the natural gas system, a modification to that 

schedule alone is not the most effective means to address gas-electric coordination issues. 

358. AEP adds that while the proposed scheduling option appears on the surface to be 

feasible within the power industry, the increased quantity of VERs and subsequent 

increased ramping capability requirements will further exacerbate the operational 

difficulties associated with the varied scheduling timelines existing between the gas and 

power industries. AEP concludes that such discrepancies place the gas-fired generation 

operators, whose typically superior ramping capabilities will become increasingly 

beneficial, in a position of speculating on fuel supply needs because they are unsure 

whether the increase in variable generation will mean an increased need for the faster 

ramping capabilities of gas. 

359. AEP notes that these differences have existed for many years, and managing them 

has become more challenging with the introduction of RTO-administered markets, as unit 

commitment is generally made by the RTO, and not the individual asset owner. AEP 

argues that any proposed scheduling practices related to incremental VER penetration 

must account for such inter-market dependencies. 

360. Spectra Entities notes that the interface issues between the gas and electric 

industries go beyond revisiting coordinating and the gas/electric scheduling timelines. 
Docket No. RM10-11-000 - 246 -

Spectra Entities argues that there are regulatory policy and market barriers discouraging 

the electric industry in some markets from contracting for adequate firm gas supply and 

firm transportation arrangements to serve those generators which must run in order to 

maintain the reliability of the electric grid. For example, the Commission’s “no-bump” 

policy and the need to coordinate scheduling of interruptible services are irrelevant 

during peak or high load days in natural gas markets, because interruptible capacity is 

rarely available on the pipeline grid under those conditions. Spectra Entities argue that 

unless these barrier issues are addressed, any changes to coordination and scheduling or 

the offering of innovative transportation solutions will not be sufficient to achieve the 

Commission’s goals. 

ii. Commission Determination

361. While comments asking the Commission to undertake reforms to natural gas 

pipeline rules and procedures in order to facilitate greater cross-market coordination are 

beyond the scope of this proceeding, we agree that the interdependence of these two 

industries merits careful attention. The Commission has recently addressed proposed 

changes to the gas pipeline nomination procedures. In the past, the Commission has 

urged the industry, working through NAESB, to consider changes to its nomination 

procedures to provide better coordination between gas and electric scheduling.337 More 

 337 See Standards for Business Practices for Interstate Natural Gas Pipelines: 

Standards for Business Practices for Public Utilities, Order No. 698, FERC Stats, & 

Regs ¶ 31,251, at P 69 (2007).
Docket No. RM10-11-000 - 247 -

recently, in Order No. 587-U, the Commission acknowledged that NAESB lacked 

consensus to implement any such changes and did not find a nationwide scheduling 

solution in response to concerns over gas pipeline nomination procedures (including the 

“no-bump” rule).338 While eschewing nationwide changes, Order No. 587-U emphasized 

that “individual pipelines may be able to offer special services or increased nomination 

opportunities that better fit the profile of gas-fired generation.”339 In fact, some pipelines 

have begun to offer special services to facilitate the flexibility needs of gas-fired 

generation.340 

362. On March 30, 2012, a number of entities submitted further comments on gaselectric coordination issues in response to a notice issued in Docket No. AD12-12-000 

that requested comments in response to a set of questions and other text concerning gaselectric interdependence issued by Commissioner Moeller on February 3, 2012. The 

Commission is currently evaluating these comments to determine what, if any, additional 

steps would be appropriate to take to facilitate coordination between the gas and electric 

industries. 

 338 Order No. 587-U, FERC Stats. & Regs. ¶ 31,307 at P 27. 

339 Id.

340 See Texas Gas Transmission LLC, 138 FERC ¶ 61,176 (2012). 
Docket No. RM10-11-000 - 248 -

3. Power Factor Design

a. Comments

363. Midwest ISO Transmission Owners state that Order No. 661 exempted wind 

generators from having to maintain power factor design criteria absent a specific finding 

in the relevant system impact study that the generator needs to maintain a specific power 

factor in order to ensure safety and reliability. Midwest ISO Transmission Owners 

submit that the Commission should convene a technical conference to examine this issue, 

or allow individual transmission providers to file to eliminate this exemption from their 

pro forma LGIAs or generator interconnection agreements. Midwest ISO Transmission 

Owners explain that wind and other VERs have obtained significant penetration levels in 

many areas of the country, such that wind is no longer a new technology that needs 

protection. Midwest ISO Transmission Owners contend that eliminating this exemption 

will ensure that wind does not receive an unfair competitive basis.

b. Commission Determination

364. Since issuance of the Proposed Rule in this proceeding, the Commission has 

directed staff to convene a technical conference in Docket No. AD12-10-000 to examine 

whether the Commission should reconsider or modify the reactive power provisions of 

Order No. 661-A and examine what evidence could be developed under Order No. 661 to 

support a request to apply reactive power requirements more broadly than to individual 
Docket No. RM10-11-000 - 249 -

wind generators during the interconnection study process.341 The Commission concludes 

that potential issues regarding the exemption provided under Order No. 661-A are better 

addressed in that proceeding. 

VI. Compliance

A. Commission Proposal

365. In the Proposed Rule, the Commission indicated that each public utility 

transmission provider must submit a compliance filing within six months of the effective 

date of the Final Rule revising its OATT and LGIA to demonstrate compliance with the 

Final Rule. The Commission indicated that to demonstrate compliance, a public utility 

transmission provider must file: (1) revisions to its OATT to implement 15-minute 

scheduling; (2) revisions to its LGIA to include a requirement for interconnection 

customers whose generating facility is a VER to provide data to the public utility 

transmission provider when the public utility transmission provider is developing and 

deploying power production forecasting for VERs; and (3) the addition of Schedule 10 to 

the OATT, which includes the same per unit rate from their currently effective Schedule 

3, and a blank or unfilled volumetric component, among other things. 

366. The Commission acknowledged that public utility transmission providers may 

have provisions in their existing OATTs and LGIAs that the Commission has deemed to 

be consistent with or superior to the pro forma OATT and LGIA. The Commission 

 341 Reactive Power Resources, Notice of Technical Conference, Docket No. 

AD12-10-000 (issued Feb. 17, 2012).
Docket No. RM10-11-000 - 250 -

indicated that where these provisions are being modified by the Final Rule, public utility 

transmission providers must either comply with the Final Rule or demonstrate that these 

previously-approved variations continue to be consistent with or superior to the pro 

forma OATT and LGIA as modified by the Final Rule. 

367. The Commission also proposed that transmission providers that are not public 

utilities would have to adopt the requirements of the Final Rule as a condition of 

maintaining the status of their safe harbor tariff or otherwise satisfying the reciprocity 

requirement of Order No. 888.342

B. Comments

368. Commenters addressing the six month timeframe generally argue that the 

proposed compliance deadline does not provide enough time for the industry to 

implement intra-hour scheduling effectively.343 Specifically, commenters assert that 

additional time is needed to allow transmission providers time to: (1) develop necessary 

revisions to inter-regional agreements and procedures, and finish ongoing pilot programs; 

and (2) evaluate all potential impacts to operations and address issues regarding 

reliability via NERC, and perhaps business standards via NAESB.

369. Southern California Edison argues that regional differences and the need to 

implement intra-hour scheduling efficiently require careful consideration of each region’s 

 342 Order No. 888, FERC Stats. & Regs. at 31,760-763.

343 E.g., MidAmerican; EEI; FriiPwr; NRECA; Southern California Edison; 

Pacific Gas & Electric; Grant PUD; NextEra; PNW Parties; Powerex; NV Energy; New 

York ISO; ISO/RTO Council.
Docket No. RM10-11-000 - 251 -

scheduling rules. Specifically, Southern California Edison suggests that the Commission 

provide three years to implement 30-minute scheduling followed by an 18-24 month 

evaluation period before deciding if 15-minute intra-hour scheduling is necessary. 

Pacific Gas & Electric recommends that the Commission lengthen the implementation 

timeline for intra-hour scheduling, so that regional technical conferences on intra-hour 

scheduling can be convened for affected transmission providers, and so that ongoing pilot 

studies on intra-hour scheduling may be completed.

370. NorthWestern comments that six months is insufficient time for a compliance 

filing implementing the intra-hour scheduling requirements of the Proposed Rule. 

NorthWestern argues that compliance will include, but not be limited to, implementation 

of software and hardware upgrades, adoption of common regional scheduling practices in 

the region with jurisdictional and non-jurisdictional balancing authorities, and hiring and 

properly training of additional staff. NorthWestern encourages the Commission to be 

flexible and allow balancing authorities the ability to define implementation timeframes, 

perhaps up to one year before the compliance filing is due. 

371. Commenters also point more generally to areas of the Proposed Rule that may 

require additional time for compliance. Midwest ISO Transmission Owners state for 

example that additional time may be needed to make changes that are highly technical or 

require an extensive stakeholder process to implement.344 Midwest ISO suggests that at 

 344 Midwest ISO Transmission Owners at 16.
Docket No. RM10-11-000 - 252 -

least 18 months should be allotted for transmission providers to submit compliance 

filings revising their OATT, LGIA, or other documents.345 MidAmerican recommends 

that sufficient time be allocated so that transmission providers may (1) evaluate and 

address all potential impacts to operations and reliability and (2) be afforded the 

necessary time to procure resources, develop and adopt administrative processes, conduct 

training, and perform testing and validation critical to successfully effectuate the 

proposed reforms. 

372. EEI suggests that the Commission not require the changes set forth in the 

Proposed Rule until the regional planning and cost allocation Final Rules have gone 

through any rehearing and legal challenges that may develop. On the other hand, 

Iberdrola supports the Commission’s proposal to require a compliance filing within six 

months; however, if the Commission extends the deadline, Iberdrola recommends that 

implementation of Schedule 10 occur coincidentally with the implementation of the other 

two proposed operational changes. 

C. Commission Determination 

373. The Commission extends the deadline for compliance filings by 6 months so that 

public utility transmission providers will have 12 months from the effective date of this 

Final Rule to submit their compliance filings. The Commission also provides the pro 

forma tariff language that public utility transmission providers must include in their 

 345 Midwest ISO at 15.
Docket No. RM10-11-000 - 253 -

OATTs and LGIAs, with modifications to the language based upon the comments 

received, as discussed within the body of this Final Rule.346 

374. Consistent with the discussion in the intra-hourly scheduling section, the 

Commission requires public utility transmission providers to revise their OATTs to 

provide an opportunity for transmission customers to submit transmission schedules at 

15-minute intervals within 12 months of the effective date of this Final Rule.347 Public 

utility transmission providers with provisions in their existing OATTs that the 

Commission has deemed to be consistent with or superior to the pro forma OATT being 

modified by the Final Rule can seek to demonstrate in their compliance filings that those 

previously-approved variations continue to be consistent with or superior to the pro 

forma OATT as modified by the Final Rule. In addition, public utility transmission 

providers may 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.

348 .

375. Consistent with the discussion in the data reporting section, the Final Rule 

modifies the compliance obligation set forth in the Proposed Rule and requires public 

 346 See Appendix A and B for the adopted pro forma OATT and LGIA provisions 

consistent with this Final Rule.

347 See Appendix A for the revised section 13.8 and 14.6 of the pro forma OATT 

provisions consistent with this Final Rule. As noted supra § IV.A.1 (Intra-Hour 

Scheduling Requirement), the implementation of 15-minute scheduling will only apply to 

intertie transactions in organized wholesale energy markets.

348 See supra § IV.A.1 (Intra-Hour Scheduling Requirement).
Docket No. RM10-11-000 - 254 -

utility transmission providers to modify their pro forma LGIAs to effectuate the data 

reporting requirement within 12 months of the effective date of this Final Rule rather than 

the six months initially proposed.349 The Commission adopts proposed Article 8.4 of the 

pro forma LGIA, as modified per the discussion in the data reporting section. The 

Commission also adopts the proposed definition of VER. The Commission appreciates 

that public utility transmission providers in some regions, including RTOs and ISOs, 

have already implemented meteorological or forced outage reporting under relevant 

tariffs, business practices and/or markets rules. Such public utility transmission providers 

may seek to demonstrate in their compliance filings how continued use of these existing 

tariffs, business practices and/or market rules is adequate to satisfy the requirements of 

this Final Rule using the independent entity variation standard set forth in Order No. 

2003, if relevant, or by demonstrating variations from the pro forma OATT are consistent 

with or superior to the requirements of this Final Rule.350 

376. The Commission concludes that 12 months is a reasonable amount of time to 

implement the requirements of this Final Rule. Many public utility transmission 

providers have already implemented some form of sub-hourly scheduling, resolving 

many of the issues that must be addressed in order to accept transmission schedules on a 

 349 See Appendix B for the revisions to the pro forma LGIA consistent with this 

Final Rule. Specifically, a new Article 8.4 and a new definition in Article 1 have been

added to the pro forma LGIA and conforming revisions have been made to the table of 

contents. 

350 See Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 910. 
Docket No. RM10-11-000 - 255 -

15-minute interval. Twelve months also is an adequate amount of time for public utility 

transmission providers to determine the extent to which meteorological and forced outage 

data are necessary to support power production forecasting. Although we are extending 

the compliance deadline to 12 months from the compliance schedule in the Proposed 

Rule, we do not believe that more than 12 months will be necessary. Therefore, we will 

not extend the compliance deadline beyond 12 months, nor will we adopt commenters’ 

other proposed recommendations.

377. Finally, the Commission also adopts the proposal that transmission providers that 

are not public utilities must adopt the requirements of the Final Rule as a condition of 

maintaining the status of their safe harbor tariff or otherwise satisfying the reciprocity 

requirement of Order No. 888.351

VII. Information Collection Statement 

378. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection and data retention requirements imposed by agency 

rules.352 Upon approval of a collection(s) of information, OMB will assign an OMB 

control number and an expiration date. Respondents subject to the filing requirements of 

a rule will not be penalized for failing to respond to these collections of information 

unless the collections of information display a valid OMB control number. 

 351 Order No. 888, FERC Stats. & Regs. at 31,760-63.

352 5 C.F.R. 1320.11(b).
Docket No. RM10-11-000 - 256 -

379. The Commission is submitting the proposed modifications to its information 

collections to OMB for review and approval in accordance with section 3507(d) of the 

Paperwork Reduction Act of 1995.353 In the Proposed Rule, the Commission solicited 

comments on the need for this information, whether the information will have practical 

utility, the accuracy of provided burden estimates, ways to enhance the quality, utility, 

and clarity of the information to be collected or retained, and any suggested methods for 

minimizing the respondent’s burden, including the use of automated information 

techniques. The Commission also included a table that listed the estimated public 

reporting burdens for the proposed reporting requirements, as well as a projection of the 

costs of compliance for the reporting requirements.

380. The Commission did not receive any comments specifically addressing the burden 

estimates provided in the Proposed Rule. However, commenters did respond to questions 

in the NOPR regarding the specific hardware, software, and personnel changes that are 

necessary to implement intra-hour scheduling. As noted in Section IV above, some 

parties argue that the cost to implement intra-hour scheduling will be modest, while other 

commenters state that implementation costs may be significant. In addition to the 

Commission’s responses to the comments previously provided, the Commission believes 

that the revised burden estimates below are representative of the average burden on 

respondents. 

 353 44 U.S.C. 3507(d).
Docket No. RM10-11-000 - 257 -

381. In the Final Rule, the Commission adds two burden categories that were not 

included in the Proposed Rule burden estimates. First, the Commission includes a burden 

estimate for transmission providers who choose to share power production forecast 

results with VERs. Second, the Commission includes a burden estimate for transmission 

providers who choose to voluntarily share VER-provided meteorological and forced 

outage data with third parties. Neither of these additional categories is required under the 

Final Rule. However, the Commission assumes that all Transmission Providers will 

implement these changes for the purposes of calculating a burden estimate. The 

Commission also notes that certain VERs will have increased burden due to submission 

of intra-hour schedules to transmission providers. However, the Commission assumes 

that only VERs who choose to participate in intra-hour scheduling are those who will 

receive at least as much benefit as the cost that must be expended. For this reason, the 

Commission is not including a burden estimate for this category in the table below.
Docket No. RM10-11-000 - 258 -

Burden Estimate and Information Collection Costs: The estimated Public Reporting 

burden and cost for the requirements contained in this Final Rule follow.

Data Collection

FERC 516 (as contained in 

Final Rule in RM10-11)

Number and 

Type of 

Respondents

[1]

Number of 

Responses

Per 

Respondent

[2]

Hours per 

Response

[3]

Total 

Annual 

Hours

[1 X 2 X 3]

Conforming tariff changes to 

require intra-hourly scheduling, 

waiver, or deviation request; 

and rate treatment terms for 

Ancillary Service 

142354

Transmission 

providers

1

8

first year 

only

1,136

first year 

only

Implementation of intra-hourly 

scheduling

142 

Transmission 

Providers

1 30

reoccurring

4,260

reoccurring

Conforming changes to 

LGIA355

142 

Transmission 

Providers

1

20

first year 

only

2,840

first year 

only

Sharing of power production 

forecasting results with VER

142 

Transmission 

Providers

1 30 

reoccurring

4,260 

reoccurring

Sharing of VER provided 

meteorological and forced 

outage data with third party 

entities (e.g. NOAA, balancing 

authority area)

142

Transmission 

Providers

1 30

reoccurring

4,260

reoccurring

 354 The Commission estimated in the NOPR that 134 transmission providers would 

have additional burdens due to the Proposed Rule. Since then, the Commission has 

identified eight additional transmission providers who are non-public utilities that file 

reciprocity open access transmission tariffs that are also expected to voluntarily comply 

with this rule.

355 Consistent with the approach taken in Order No. 2003, public utility 

transmission providers with power production forecasting systems in place via tariff 

provisions and/or other mechanisms will be required to demonstrate that deviations from 

the pro forma LGIA are consistent with or superior to the pro forma LGIA. 
Docket No. RM10-11-000 - 259 -

Data Collection

FERC 516 (as contained in 

Final Rule in RM10-11)

Number and 

Type of 

Respondents

[1]

Number of 

Responses

Per 

Respondent

[2]

Hours per 

Response

[3]

Total 

Annual 

Hours

[1 X 2 X 3]

Provision of meteorological and 

forced outage data to public 

utility transmission providers 

for use in power production 

forecasting356

160357

Interconnection 

Customers with 

VERs per year

1 60

reoccurring

9,600

reoccurring

Totals

26,356358

first year + 

reoccurring

22,380359

subsequent 

years

Cost to Comply: The Commission has projected the total cost of compliance to be 

$3,004,584 in the first year, and $2,551,330 each year after.

Total Annual Hours in the first year (26,356 hours) @ $114 an hour [average cost of 

attorney ($200 per hour), consultant ($150), technical ($80), and administrative support 

($25)] = $3,004,584.

Total Annual Hours in subsequent years (22,380 hours) @ $114 an hour = $2,551,320.

 356 Once a data exchange is implemented, the Commission expects that this 

process will be automated and require little to no day to day burden.

357 The Commission estimates that there will be approximately 160 VERs that will 

sign an LGIA each year during the period from July 2012- July 2015 potentially subject 

to this requirement. This update from the NOPR represents more recent data.

358 First year hours total 26,356, the sum of first year and reoccurring hours. 

359 Annual hours total 22,380, the sum of all reoccurring hours.
Docket No. RM10-11-000 - 260 -

Title: FERC-516, Electric Rate Schedules and Tariff Filings

Action: Proposed Collection.

OMB Control No. 1902-0096

Respondents for this Rulemaking: Transmission Providers (an RTO or ISO also may file 

some materials on behalf of its members) and Variable Energy Resources.

Frequency of Information: As indicated in the table.

Necessity of Information: The Federal Energy Regulatory Commission is adopting these 

amendments to the pro forma OATT to remedy operational challenges related to the 

increased integration of VERs to the bulk electric system. The purpose of this Final Rule 

is to strengthen the pro forma OATT, so VERs can be reliably and efficiently integrated 

into the electric grid and to ensure that Commission-jurisdictional services are provided 

at rates, terms and conditions that are just and reasonable and not unduly discriminatory 

or preferential. This Final Rule seeks to achieve this goal by amending the pro forma

OATT and LGIA to incorporate provisions that require intra-hourly transmission 

scheduling and require interconnection customers whose generating facilities are VERs to 

provide meteorological and operational data to public utility transmission providers for 

the purpose of power production forecasting. The Commission also provides guidance 

regarding the development of proposals for generator regulation service.

Internal Review: The Commission has reviewed the proposed changes and has 

determined that the changes are necessary. These requirements conform to the 

Commission’s need for efficient information collection, communication, and 

management within the energy industry. The Commission has assured itself, by means of 
Docket No. RM10-11-000 - 261 -

internal review, that there is specific, objective support for the burden estimates 

associated with the information collection requirements.

382. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], 

e-mail: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 

Comments concerning the collection of information and the associated burden 

estimate(s), may also be sent to the Office of Information and Regulatory Affairs, Office 

of Management and Budget, 725 17th Street, NW, Washington, DC 20503 [Attention: 

Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-4638, 

fax (202) 395-7285]. Due to security concerns, comments should be sent electronically 

to the following e-mail address: oira_submission@omb.eop.gov. Comments submitted 

to OMB should include OMB Control No. 1902-0096 and Docket No. RM10-11-000.

VIII. Environmental Analysis

383. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.360 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact Statement is required for this Proposed Rule 

 360 Regulations Implementing the National Environmental Policy Act of 1969, 

Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 1986-

1990 ¶ 30,783 (1987).
Docket No. RM10-11-000 - 262 -

under § 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the FPA relating to the 

filing of schedules containing all rates and charges for the transmission or sale of electric 

energy subject to the Commission’s jurisdiction, plus the classification, practices, 

contracts and regulations that affect rates, charges, classifications, and services.361

IX. Regulatory Flexibility Act Analysis

384. The Regulatory Flexibility Act of 1980 (RFA)362 generally requires a description 

and analysis of Final Rules that will have a significant economic impact on a substantial 

number of small entities. This Final Rule applies to public utilities that own, control or 

operate interstate transmission facilities363 and to variable energy resources. The total 

estimated number of small public utility transmission providers364 impacted by this Final 

Rule is estimated to be ten. The Commission assumes that the Final Rule will impact all 

the applicable small transmission providers equally at an average cost of $13,500 per 

year. The Commission does not consider this to be a significant economic impact. In 

 361 18 C.F.R. 380.4(a)(15) (2010). 

362 5 U.S.C. 601-612 (2006). 

363 Other than those that have received waiver of the obligation to comply with 

Order Nos. 888, 889, and 890.

364 A “small entity” as referenced in the RFA refers to the definition provided in 

section 3 of the Small Business Act where a firm is “small” if, including its affiliates, it is 

primarily engaged in the generation, transmission, and/or distribution of electric energy 

for sale and its total electric output for the preceding fiscal year did not exceed 4 million 

megawatt hours. 
Docket No. RM10-11-000 - 263 -

any event, each of these entities may seek waiver of these requirements.365 The 

Commission estimates that all of the applicable VERs (160 per year) are small. Of these 

160 entities, approximately 100 that are greater than 20 MW will be required to comply 

with the Final Rule and approximately 60 that are 20 MW or less will have the option to 

comply with the rule. The Commission estimates that each VER will have an average 

cost of $6,800 per year because of the Final Rule. The Commission does not consider 

this to be a significant economic impact on these small entities. The costs incurred by 

VERs due to this rule are offset by an expected reduction in energy imbalance penalties 

that will be assessed to VERs in the future due to improved forecasting and reduced 

uncertainty across 15-minute scheduling periods compared to hour-long scheduling 

periods. Accordingly, the Commission certifies that this Final Rule will not have a 

significant economic impact on a substantial number of small entities.

X. Document Availability

385. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC’s Home Page 

(http://www.ferc.gov) and in FERC’s Public Reference Room during normal business 

 365 The criteria for waiver that would be applied under this rulemaking for small 

entities is unchanged from that used to evaluate requests for waiver under Order Nos. 

888, 889, and 890. 
Docket No. RM10-11-000 - 264 -

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426.

386. From FERC’s Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field.

387. User assistance is available for eLibrary and the FERC’s website during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-

8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

XI. Effective Date and Congressional Notification

388. These regulations are effective [insert date 60 days after publication in the 

FEDERAL REGISTER]. The Commission has determined, with the concurrence of the 

Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule 

is not a “major rule” as defined in section 351 of the Small Business Regulatory 

Enforcement Fairness Act of 1996. The Commission will submit this Final Rule to both 

houses of Congress and the Government Accountability Office.
Docket No. RM10-11-000 - 265 -

List of subjects in 18 C.F.R. Part 35 

Electric power rates

Electric utilities

Reporting and record-keeping requirements

By the Commission. Commissiner LaFleur is dissenting in part with a separate statement

 attached.

 Commissioner Clark voting present.

(S E A L)

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket No. RM10-11-000 - 266 -

PART 35—FILING OF RATE SCHEDULES AND TARIFFS

1. The authority citation for Part 35 continues to read as follows: 

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 71-7352.

2. Amend § 35.28 as follows:

a. Paragraphs (c)(1) through (c)(1)(iii) are revised.

b. Paragraphs (c)(1)(v) and (c)(1)(vi) are revised.

c. Paragraphs (c)(3) and (c)(3)(ii) are revised.

d. Paragraphs (c)(4) through (c)(4)(ii) are revised.

e. Paragraph (d) is revised.

f. Paragraphs (d)(1) and (d)(2) are deleted.

g. Paragraphs (e)(1) and (e)(1)(ii) are revised.

h. Paragraphs (f)(1) and (f)(1)(i) are revised.

i. Paragraphs (f)(1)(ii) through (f)(1)(iv) are deleted.

j. Paragraph (f)(3) is revised.

k. Paragraphs (f)(3)(i), (f)(3)(ii), and (f)(4) are deleted.

§ 35.28 Non-discriminatory open access transmission tariff.

* * * * *

(c) Non-discriminatory open access transmission tariffs. 

(1) Every public utility that owns, controls, or operates facilities used for the 

transmission of electric energy in interstate commerce must have on file with the 

Commission an open access transmission tariff of general applicability for transmission 
Docket No. RM10-11-000 - 267 -

services, including ancillary services, over such facilities. Such tariff must be the 

pro forma tariff promulgated by the Commission, as amended from time to time, or such 

other tariff as may be approved by the Commission consistent with the principles set 

forth in Commission rulemaking proceedings promulgating and amending the pro forma

tariff. 

(i) Subject to the exceptions in paragraphs (c)(1)(ii), (c)(1)(iii), (c)(1)(iv), and 

(c)(1)(v) of this section, the open access transmission tariff, which tariff must be the pro 

forma tariff required by Commission rulemaking proceedings promulgating and 

amending the pro forma tariff, and accompanying rates must be filed no later than 60 

days prior to the date on which a public utility would engage in a sale of electric energy 

at wholesale in interstate commerce or in the transmission of electric energy in interstate 

commerce.

(ii) If a public utility owns, controls, or operates facilities used for the 

transmission of electric energy in interstate commerce, it must file the revisions to its

open access transmission tariff required by Commission rulemaking proceedings 

promulgating and amending the pro forma tariff, pursuant to section 206 of the FPA and 

accompanying rates pursuant to section 205 of the FPA in accordance with the 

procedures set forth in Commission rulemaking proceedings promulgating and amending 

the pro forma tariff. 

(iii) If a public utility owns, controls, or operates transmission facilities used for 

the transmission of electric energy in interstate commerce, such facilities are jointly 

owned with a non-public utility, and the joint ownership contract prohibits transmission 
Docket No. RM10-11-000 - 268 -

service over the facilities to third parties, the public utility with respect to access over the 

public utility's share of the jointly owned facilities must file the revisions to its open 

access transmission tariff required by Commission rulemaking proceedings promulgating 

and amending the pro forma tariff pursuant to section 206 of the FPA and accompanying 

rates pursuant to section 205 of the FPA in accordance with the procedures set forth in 

Commission rulemaking proceedings promulgating and amending the pro forma tariff. 

* * * * *

(v) If a public utility obtains a waiver of the tariff requirement pursuant to 

paragraph (d) of this section, it does not need to file the open access transmission tariff 

required by this section.

(vi) Any public utility that seeks a deviation from the pro forma tariff 

promulgated by the Commission, as amended from time to time, must demonstrate that 

the deviation is consistent with the principles set forth in Commission rulemaking 

proceedings promulgating and amending the pro forma tariff. 

* * * * *

(3) Every public utility that owns, controls, or operates facilities used for the 

transmission of electric energy in interstate commerce, and that is a member of a power 

pool, public utility holding company, or other multi-lateral trading arrangement or 

agreement that contains transmission rates, terms or conditions, must have on file a joint 

pool-wide or system-wide open access transmission tariff, which tariff must be the 

pro forma tariff promulgated by the Commission, as amended from time to time, or such 

other open access transmission tariff as may be approved by the Commission consistent 
Docket No. RM10-11-000 - 269 -

with the principles set forth in Commission rulemaking proceedings promulgating and 

amending the pro forma tariff. 

* * * * *

(ii) For any power pool, public utility holding company or other multi-lateral 

arrangement or agreement that contains transmission rates, terms or conditions and that is

executed on or before May 14, 2007, a public utility member of such power pool, public 

utility holding company or other multi-lateral arrangement or agreement that owns, 

controls, or operates facilities used for the transmission of electric energy in interstate 

commerce must file the revisions to its joint pool-wide or system-wide open access 

transmission tariff required by Commission rulemaking proceedings promulgating and 

amending the pro forma tariff pursuant to section 206 of the FPA and accompanying 

rates pursuant to section 205 of the FPA in accordance with the procedures set forth in 

Commission rulemaking proceedings promulgating and amending the pro forma tariff.

* * * * * 

(4) Consistent with paragraph (c)(1) of this section, every Commissionapproved ISO or RTO must have on file with the Commission an open access 

transmission tariff of general applicability for transmission services, including ancillary 

services, over such facilities. Such tariff must be the pro forma tariff promulgated by the 

Commission, as amended from time to time, or such other tariff as may be approved by 

the Commission consistent with the principles set forth in Commission rulemaking 

proceedings promulgating and amending the pro forma tariff. 
Docket No. RM10-11-000 - 270 -

(i) Subject to paragraph (c)(4)(ii) of this section, a Commission-approved ISO 

or RTO must file the revisions to its open access transmission tariff required by 

Commission rulemaking proceedings promulgating and amending the pro forma tariff 

pursuant to section 206 of the FPA and accompanying rates pursuant to section 205 of the 

FPA in accordance with the procedures set forth in Commission rulemaking proceedings 

promulgating and amending the pro forma tariff.

(ii) If a Commission-approved ISO or RTO can demonstrate that its existing 

open access transmission tariff is consistent with or superior to the pro forma tariff 

promulgated by the Commission, as amended from time to time, the Commissionapproved ISO or RTO may instead set forth such demonstration in its filing pursuant to 

section 206 in accordance with the procedures set forth in Commission rulemaking 

proceedings promulgating and amending the pro forma tariff.

(d) Waivers. A public utility subject to the requirements of this section and 

Order No. 889, FERC Stats. & Regs. ¶ 31,037 (Final Rule on Open Access Same-Time 

Information System and Standards of Conduct) may file a request for waiver of all or part 

of the requirements of this section, or Part 37 (Open Access Same-Time Information 

System and Standards of Conduct for Public Utilities), for good cause shown. Except as 

provided in paragraph (f) of this section, an application for waiver must be filed no later 

than 60 days prior to the time the public utility would have to comply with the 

requirement.

* * * * *

 
Docket No. RM10-11-000 - 271 -

(e) Non-public utility procedures for tariff reciprocity compliance. 

(1) A non-public utility may submit an open access transmission tariff and a 

request for declaratory order that its voluntary transmission tariff meets the requirements 

of Commission rulemaking proceedings promulgating and amending the pro forma tariff. 

* * * * * 

(ii) If the submittal is found to be an acceptable open access transmission tariff, 

an applicant in a Federal Power Act (FPA) section 211 or 211A proceeding against the 

non-public utility shall have the burden of proof to show why service under the open 

access transmission tariff is not sufficient and why a section 211 or 211A order should be 

granted.

(2) A non-public utility may file a request for waiver of all or part of the 

reciprocity conditions contained in a public utility open access transmission tariff, for 

good cause shown. An application for waiver may be filed at any time.

(f) Standard generator interconnection procedures and agreements.

(1) Every public utility that is required to have on file a non-discriminatory 

open access transmission tariff under this section must amend such tariff by adding the 

standard interconnection procedures and agreement and the standard small generator 

interconnection procedures and agreement required by Commission rulemaking 

proceedings promulgating and amending such interconnection procedures and 

agreements, or such other interconnection procedures and agreements as may be required 

by Commission rulemaking proceedings promulgating and amending the standard 
Docket No. RM10-11-000 - 272 -

interconnection procedures and agreement and the standard small generator 

interconnection procedures and agreement.

(i) Any public utility that seeks a deviation from the standard interconnection 

procedures and agreement or the standard small generator interconnection procedures and 

agreement required by Commission rulemaking proceedings promulgating and amending 

such interconnection procedures and agreements, must demonstrate that the deviation is 

consistent with the principles set forth in Commission rulemaking proceedings 

promulgating and amending such interconnection procedures and agreements.

* * * * * 

(3) A public utility subject to the requirements of this paragraph may file a 

request for waiver of all or part of the requirements of this paragraph, for good cause 

shown.
Docket No. RM10-11-000 - 273 -

Note: The following appendices will not be published in the Code of Federal Regulations.

Appendix A: List of Short Names of Commenters on the Federal Energy Regulatory 

Commission’s Notice of Proposed Rulemaking on Integration of Variable Energy 

Resources—Docket No. RM10-11-000, November 2010

Short Name or Acronym Commenter

A123 A123 Systems, Inc.

AEP American Electric Power Service 

Corporation

ALLETE ALLETE Inc.

ACSF American Clean Skies Foundation

Alstom Alstom Grid, Inc.

American Gas American Gas Association

APPA American Public Power Association

Argonne National Lab Argonne National Laboratory

Arizona Corporation Commission Arizona Corporation Commission

Avista Avista Corporation

AWEA American Wind Energy Association

Beacon Power Beacon Power Corporation

Bonneville Power Bonneville Power Administration

BP Companies BP Energy Company and BP Wind Energy 

North America, Inc.

BrightSource BrightSource Energy, Inc.

Business Council Business Council for Sustainable Energy

CESA California Energy Storage Alliance
Docket No. RM10-11-000 - 274 -

California State Water Project California Department of Water Resources 

State Water Project

California ISO California Independent System Operator 

Corporation

California PUC California Public Utilities Commission

CEERT Center for Energy Efficiency and Renewable 

Technologies

Center for Rural Affairs Center for Rural Affairs

CMUA California Municipal Utilities Association;

Cities of Alameda, Anaheim, Azusa, Banning, 

Burbank, Cerritos, Colton, Corona, Glendale, 

Gridley, Healdsburg, Hercules, Lodi, Lompoc, 

Moreno Valley, Needles, Palo Alto, Pasadena, 

Pittsburg, Rancho Cucamonga, Redding, 

Riverside, Roseville, Santa Clara, Shasta Lake, 

Ukiah, and Vernon; the Imperial, Merced, 

Modesto, and Turlock Irrigation Districts; the 

Northern California Power Agency; Southern 

California Public Power Authority; 

Transmission Agency of Northern California; 

Lassen Municipal Utility District; Power and 

Water Resources Pooling Authority; 

Sacramento Municipal Utility District; the 

Trinity and Truckee Donner Public Utility 

Districts; the Metropolitan Water District of 

Southern California; and the City and County of 

San Francisco, Hetch-Hetchy

Clean Line Clean Line Energy Partners, LLC

CGC Coalition for Green Capital

Defenders of Wildlife Wilderness Society and Defenders of Wildlife

Detroit Edison Detroit Edison Company

Dominion Dominion Resources Services, Inc.
Docket No. RM10-11-000 - 275 -

Duke Duke Energy Corporation

EEI Edison Electric Institute

ELCON Electricity Consumers Resource Council

EPSA Electric Power Supply Association

ENBALA ENBALA Power Networks

Entergy Entergy Services, Inc.

Environmental Defense Fund Environmental Defense Fund

E.ON C&R E.ON Climate & Renewables North America

Exelon Exelon Corporation

Federal Trade Commission Federal Trade Commission

FirstEnergy FirstEnergy Service Company

First Wind First Wind Energy, LLC

FriiPwr FriiPwr USA Ltd

Grant PUD Public Utility District No. 2 of Grant County, 

Washington

Grays Harbor PUD Public Utility District No. 1 of Grays Harbor

County, Washington

Iberdrola Iberdrola Renewables, Inc.

Idaho Power Idaho Power Company

Independent Energy Producers Independent Energy Producers Association

Independent Power Producers Arizona Competitive Power Alliance;

Coalition-West Colorado Independent Energy Association; 

Independent Energy Producers Association 

(California); New Mexico Independent Power 

Producers Coalition; and the Northwest & 
Docket No. RM10-11-000 - 276 -

Intermountain Power Producers Coalition.

INGAA Interstate Natural Gas Association of America

Invenergy Wind Invenergy Wind Development LLC

ISO New England ISO New England Inc. and the New England 

Power Pool

ISO/RTO Council Alberta Electricity System Operator; California 

Independent System Operator; Electric 

Reliability Council of Texas; Independent 

Electricity System Operator of Ontario; ISO 

New England, Inc.; Midwest Independent 

Transmission System Operator, Inc.; New 

Brunswick System Operator; New York 

Independent System Operator, Inc.; PJM 

Interconnection, L.L.C.; and Southwest Power 

Pool, Inc.

ITC Companies ITCTransmission; Michigan Electric 

Transmission Company, LLC; ITC Midwest 

LLC; and ITC Great Plains, LLC

Joint Parties Arizona Public Service Company; The Boeing 

Company, El Paso Electric; New York 

Independent System Operator; Old Dominion 

Electric Cooperative; PJM Interconnection, 

L.L.C.; Salt River Project Agriculture 

Improvement and Power District; Southwest 

Power Pool; Tennessee Valley Authority; 

Tucson Electric Power Company; UNS Gas, 

Inc.; and the Vermont Department of Public 

Service

Joint Initiative Joint Initiative Facilitators

Large Public Power Council Austin Energy; Chelan County Public Utility 

District No. 1; Clark Public Utilities, Colorado 

Springs Utilities; CPS Energy (San Antonio); 

ElectriCities of North Carolina; Grant County 

Public Utility District; IID Energy (Imperial
Docket No. RM10-11-000 - 277 -

Irrigation District); JEA (Jacksonville, FL); 

Long Island Power Authority; Los Angeles 

Department of Water and Power; Lower 

Colorado River Authority; MEAG Power; 

Nebraska Public Power District; New York 

Power Authority; Omaha Public Power District; 

Orlando Utilities Commission; Platte River 

Power Authority; Puerto Rico Electric Power 

Authority; Sacramento Municipal Utility 

District; Salt River Project; Santee Cooper; 

Seattle City Light; Snohomish County Public 

Utility District No. 1; and Tacoma Public 

Utilities

LADWP Department of Water and Power of the City of 

Los Angeles

Massachusetts DPU Massachusetts Department of Public Utilities

MidAmerican MidAmerican Energy Holdings Company

Midwest Energy Midwest Energy, Inc.

Midwest ISO Midwest Independent Transmission System 

Operator, Inc.

Midwest ISO Transmission Owners Ameren Services Company, as agent for Union 

Electric Company d/b/a Ameren Missouri; 

Ameren Illinois Company d/b/a Ameren Illinois 

and Ameren Transmission Company of Illinois; 

American Transmission Company LLC; Big 

Rivers Electric Corporation; City Water, Light 

& Power (Springfield, IL); Dairyland Power 

Cooperative; Duke Energy Corporation for 

Duke Energy Ohio, Inc., Duke Energy Indiana, 

Inc., and Duke Energy Kentucky, Inc.; Great 

River Energy; Hoosier Energy Rural Electric 

Cooperative, Inc. (“Hoosier”); Indiana 

Municipal Power Agency; Indianapolis Power 

& Light Company (“IPL”); Michigan Public 

Power Agency; MidAmerican Energy 

Company; Minnesota Power (and its subsidiary
Docket No. RM10-11-000 - 278 -

Superior Water, L&P); Montana-Dakota 

Utilities Co.; Northern Indiana Public

Service Company; Northern States Power 

Company, a Minnesota corporation, and

Northern States Power Company, a Wisconsin 

corporation, subsidiaries of Xcel Energy Inc. 

(“Xcel Energy”); NorthWestern Wisconsin 

Electric Company; Otter Tail Power Company; 

Southern Illinois Power Cooperative; Southern 

Indiana Gas & Electric Company (d/b/a Vectren 

Energy Delivery of Indiana); Southern

Minnesota Municipal Power Agency; Wabash 

Valley Power Association, Inc.; and

Wolverine Power Supply Cooperative, Inc.

M-S-R Public Power Agency Modesto Irrigation District; City of Santa Clara, 

California; and City of Redding, California

Montana PSC Montana Public Service Commission

NEMA National Electrical Manufacturers Association 

National Grid National Grid USA

NRECA National Rural Electric Cooperative Association

Natural Gas Natural Gas Supply Association

NaturEner NaturEner USA, LLC

NE Conference of PUCs New England Conference of Public Utilities 

Commissioners

NESCOE New England States Committee on Electricity

NV Energy Nevada Power Company and Sierra Pacific 

Power Company

New York ISO New York Independent System Operator, Inc.

NextEra NextEra Energy, Inc.

NERC North American Electric Reliability 
Docket No. RM10-11-000 - 279 -

Corporation

NAESB North American Energy Standards Board

NOAA National Oceanic and Atmospheric 

Administration

NorthWestern NorthWestern Corporation

Organization of Midwest ISO States Organization of Midwest ISO States

Oregon & New Mexico PUC Public Utility Commissioners of Oregon and 

New Mexico and Paul Newman, Arizona 

Commissioner

Pacific Gas & Electric Pacific Gas and Electric Company

PNW Parties Avista Corporation; the Bonneville Power 

Administration; Idaho Power Company; 

NorthWestern Corporation, dba NorthWestern 

Energy; PacifiCorp; Portland General Electric 

Company; the Public Generating Pool (Tacoma 

Power, Eugene Water and Electric Board, and 

Public Utility Districts for Chelan, Clark, 

Cowlitz, Douglas, Grant, Klickitat, Pend 

Oreille, and Snohomish counties); the Public 

Power Council; Puget Sound Energy, Inc.; and 

Seattle City Light

PJM PJM Interconnection, L.L.C.

Powerex Powerex Corporation

Public Interest Organizations Alliance for Clean Energy New York; Center 

for Rural Affairs; Citizens Utility Board of 

Wisconsin; Climate and Energy Project; 

Conservation Law Foundation; Defenders of 

Wildlife; Energy Conservation Council of 

Pennsylvania; Energy Future Coalition;

Environment Northeast; Environmental Defense 

Fund; Environmental Law & Policy Center; 

Fresh Energy; Great Plains Institute; Natural 

Resources Defense Council; Office of the Ohio 
Docket No. RM10-11-000 - 280 -

Consumers’ Counsel; Pace Energy and Climate 

Center; Project for Sustainable FERC Energy 

Policy; Sierra Club; The Wilderness Society; 

Union of Concerned Scientists; Western Grid 

Group; Western Resource Advocates; and Wind 

on the Wires

Public Power Council Public Power Council

Puget Puget Sound Energy, Inc.

Recycled Energy Recycled Energy Development

RENEW Renewable Energy New England, Inc.

RenewElec The RenewElec Project

SMUD Sacramento Municipal Utility District

San Diego Gas & Electric San Diego Gas & Electric Company

Snohomish County PUD Public Utility District No. 1 of Snohomish 

County, Washington

SEIA Solar Energy Industries Association and the 

Large-Scale Solar Association

Southern California Edison Southern California Edison Company

Southern Southern Company Services, Inc.

Southern MN Municipal Southern Minnesota Municipal Power Agency

SWEA Southwest Energy Alliance

Southwestern Southwestern Power Administration

Spectra Entities Spectra Energy Transmission, LLC and Spectra 

Energy Partners, LP

Sunflower and Mid-Kansas Sunflower Electric Power Corporation and MidKansas Electric Company, LLC
Docket No. RM10-11-000 - 281 -

TA Miller T.A. Miller

Tacoma Power City of Tacoma, Department of Public Utilities, 

Light Division (Washington)

Tres Amigas Tres Amigas LLC

TVA Tennessee Valley Authority

US Bureau of Reclamation United States Bureau of Reclamation

Utility Economic Engineers Utility Economic Engineers

Vestas Vestas-American Wind Technology, Inc.

Viridity Energy Viridity Energy, Inc.

Vote Solar Vote Solar Initiative

WUTC Washington Utilities and Transportation 

Commission

WestConnect Arizona Public Service Company; El Paso 

Electric Company, Imperial Irrigation District; 

NV Energy, Public Service Company of 

Colorado; Public Service Company of New 

Mexico; Sacramento Municipal Utility District; 

Salt River Project; Southwest Transmission 

Cooperative, Inc.; Transmission Agency of 

Northern California; Tri-State Generation and 

Transmission Association, Inc.; Tucson Electric 

Power Company and Western Area Power 

Administration

Western Farmers Western Farmers Electric Cooperative

Western Grid Western Grid Group

Xcel Xcel Energy Services Inc.

Xtreme Power Xtreme Power Inc.
Docket No. RM10-11-000 - 282 -

Appendix B: Pro Forma Open Access Transmission Tariff

The Commission amends the following sections of the pro forma OATT:

a. Section 13.8

b. Section 14.6

13.8 Scheduling of Firm Point-To-Point Transmission Service: 

Schedules for the Transmission Customer’s Firm Point-To-Point 

Transmission Service must be submitted to the Transmission Provider no later 

than 10:00 a.m. [or a reasonable time that is generally accepted in the region 

and is consistently adhered to by the Transmission Provider] of the day prior 

to commencement of such service. Schedules submitted after 10:00 a.m. will 

be accommodated, if practicable. Hour-to-hour and intra-hour (four intervals 

consisting of fifteen minute schedules) schedules of any capacity and energy 

that is to be delivered must be stated in increments of 1,000 kW per hour [or a 

reasonable increment that is generally accepted in the region and is 

consistently adhered to by the Transmission Provider]. Transmission 

Customers within the Transmission Provider’s service area with multiple 

requests for Transmission Service at a Point of Receipt, each of which is 

under 1,000 kW per hour, may consolidate their service requests at a common 

point of receipt into units of 1,000 kW per hour for scheduling and billing 

purposes. Scheduling changes will be permitted up to twenty (20) minutes [or 

a reasonable time that is generally accepted in the region and is consistently 
Docket No. RM10-11-000 - 283 -

adhered to by the Transmission Provider] before the start of the next 

scheduling interval provided that the Delivering Party and Receiving Party 

also agree to the schedule modification. The Transmission Provider will 

furnish to the Delivering Party’s system operator, hour-to-hour and intra-hour 

schedules equal to those furnished by the Receiving Party (unless reduced for 

losses) and shall deliver the capacity and energy provided by such schedules. 

Should the Transmission Customer, Delivering Party or Receiving Party 

revise or terminate any schedule, such party shall immediately notify the 

Transmission Provider, and the Transmission Provider shall have the right to 

adjust accordingly the schedule for capacity and energy to be received and to 

be delivered.

14.6 Scheduling of Non-Firm Point-To-Point Transmission Service: 

Schedules for Non-Firm Point-To-Point Transmission Service must be 

submitted to the Transmission Provider no later than 2:00 p.m. [or a 

reasonable time that is generally accepted in the region and is consistently 

adhered to by the Transmission Provider] of the day prior to commencement 

of such service. Schedules submitted after 2:00 p.m. will be accommodated, 

if practicable. Hour-to-hour and intra-hour (four intervals consisting of fifteen 

minute schedules) schedules of energy that is to be delivered must be stated in 

increments of 1,000 kW per hour [or a reasonable increment that is generally 

accepted in the region and is consistently adhered to by the Transmission 
Docket No. RM10-11-000 - 284 -

Provider]. Transmission Customers within the Transmission Provider’s 

service area with multiple requests for Transmission Service at a Point of 

Receipt, each of which is under 1,000 kW per hour, may consolidate their 

schedules at a common Point of Receipt into units of 1,000 kW per hour. 

Scheduling changes will be permitted twenty (20) minutes [or a reasonable 

time that is generally accepted in the region and is consistently adhered to by 

the Transmission Provider] before the start of the next scheduling interval, 

provided that the Delivering Party and Receiving Party also agree to the 

schedule modification. The Transmission Provider will furnish to the 

Delivering Party’s system operator, hour-to-hour and intra-hour schedules 

equal to those furnished by the Receiving Party (unless reduced for losses) 

and shall deliver the capacity and energy provided by such schedules. Should 

the Transmission Customer, Delivering Party or Receiving Party revise or 

terminate any schedule, such party shall immediately notify the Transmission 

Provider, and the Transmission Provider shall have the right to adjust 

accordingly the schedule for capacity and energy to be received and to be 

delivered.
Docket No. RM10-11-000 - 285 -

Appendix C: Pro Forma Large Generator Interconnection Agreement 

The Commission proposes to amend and/or add the following sections of the pro forma

LGIA:

a. Table of Contents (Add Article 8.4, Provision of Data from a Variable 

Energy Resource)

b. Article 1 (Add definition of Variable Energy Resource)

c. Article 8.4

Article 1 Definition

Variable Energy Resource shall mean 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.

Article 8.4 Provision of Data from a Variable Energy Resource 

The Interconnection Customer whose Generating Facility is a Variable Energy 

Resource shall provide meteorological and forced outage data to the Transmission 

Provider to the extent necessary for the Transmission Provider’s development and 

deployment of power production forecasts for that class of Variable Energy Resources. 

The Interconnection Customer with a Variable Energy Resource having wind as the 

energy source, at a minimum, will be required to provide the Transmission Provider with 

site-specific meteorological data including: temperature, wind speed, wind direction, and 

atmospheric pressure. The Interconnection Customer with a Variable Energy Resource 
Docket No. RM10-11-000 - 286 -

having solar as the energy source, at a minimum, will be required to provide the 

Transmission Provider with site-specific meteorological data including: temperature, 

atmospheric pressure, and irradiance. The Transmission Provider and Interconnection 

Customer whose Generating Facility is a Variable Energy Resource shall mutually agree 

to any additional meteorological data that are required for the development and 

deployment of a power production forecast. The Interconnection Customer whose 

Generating Facility is a Variable Energy Resource also shall submit data to the 

Transmission Provider regarding all forced outages to the extent necessary for the 

Transmission Provider’s development and deployment of power production forecasts for 

that class of Variable Energy Resources. The exact specifications of the meteorological 

and forced outage data to be provided by the Interconnection Customer to the 

Transmission Provider, including the frequency and timing of data submittals, shall be 

made taking into account the size and configuration of the Variable Energy Resource, its 

characteristics, location, and its importance in maintaining generation resource adequacy 

and transmission system reliability in its area. All requirements for meteorological and 

forced outage data must be commensurate with the power production forecasting 

employed by the Transmission Provider. Such requirements for meteorological and 

forced outage data are set forth in Appendix C, Interconnection Details, of this LGIA, as 

they may change from time to time.
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Integration of Variable Energy Resources Docket No. RM10-11-000

(Issued June 22, 2012)

LaFLEUR, Commissioner, dissenting in part:

I am dissenting in part on this Final Rule. 

I strongly support renewable energy, and I have stated many times that I believe 

one of the most important jobs of this Commission is to support the development 

of rules to address new power supply choices being made at the state and federal 

level. For that reason, I support the requirements in the rule for intra-hour 

scheduling and power production forecasting, as well as the guidance we provide 

on generator regulation service charges. 

I am dissenting on the narrow point of the compliance requirements in the Final 

Rule. As noted in the rule, we heard from many parties about ongoing efforts to 

establish intra-hour scheduling and other market improvements in various regions. 

However, the rule as issued would only allow parties to demonstrate compliance 

through incremental reforms beyond those already underway, without any 

explanation of why the ongoing efforts are insufficient. I would give regions more 

flexibility to demonstrate on compliance that these ongoing efforts meet the 

objectives of the rule. 

Accordingly, I respectfully dissent in part. 

______________________________

Cheryl A. LaFleur 

Commissioner