133 FERC ¶ 61,149 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

[Docket No. RM10-11-000] 

Integration of Variable Energy Resources 

(November 18, 2010) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: In this Notice of Proposed Rulemaking, the Federal Energy Regulatory 

Commission proposes to reform the pro forma Open Access Transmission Tariff to 

remove unduly discriminatory practices and to ensure just and reasonable rates for 

Commission-jurisdictional services. Accordingly, the Proposed Rule would: (1) require 

public utility transmission providers to offer intra-hourly transmission scheduling; 

(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 operational data to public utility transmission 

providers for the purpose of power production forecasting; and (3) add a generic ancillary 

service rate schedule through which public utility transmission providers will offer 

regulation service to transmission customers delivering energy from a generator located 

within the transmission provider’s balancing authority area. The proposed reforms will 

remove barriers to the integration of variable energy resources. 
Docket No. RM10-11-000 - 2 - 

DATES: Comments are due [Insert_Date that is 60 days after publication in the

FEDERAL REGISTER]

ADDRESSES: You may submit comments, identified by docket number and in 

accordance with the requirements posted on the Commission’s web site, 

http://www.ferc.gov. Comments may be submitted by any of the following methods: 

 Agency Web Site: Documents created electronically using word processing 

software should be filed in native applications or print-to-PDF format, and not in a 

scanned format, at http://www.ferc.gov/docs-filing/efiling.asp. 

 Mail/Hand Delivery: Commenters unable to file comments electronically must 

mail or hand deliver an original copy of their comments to: Federal Energy 

Regulatory Commission, Secretary of the Commission, 888 First Street, NE, 

Washington, DC 20426. These requirements can be found on the Commission’s 

website, see, e.g., the “Quick Reference Guide for Paper Submissions,” available 

at http://www.ferc.gov/docs-filing/efiling.asp, or via phone from FERC Online 

Support at 202-502-6652 or toll-free at 1-866-208-3676. 

FOR FURTHER INFORMATION CONTACT: 

Mk Shean (Technical Information) 

Office of Energy Policy and Innovation 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-6792 

Mk.Shean@ferc.gov 

Andrea Hilliard (Legal Information) 
Docket No. RM10-11-000 - 3 - 

Office of General Counsel – Energy Markets 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-8288 

Andrea.Hilliard@ferc.gov 

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

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

NOTICE OF PROPOSED RULEMAKING 

TABLE OF CONTENTS

Paragraph Numbers

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

II. Background...................................................................................................................... 6.

III. The Need for Reform...................................................................................................... 12.

IV. Summary of Proposed Reforms ..................................................................................... 19.

V. Proposed Reforms............................................................................................................ 25.

A. Intra-hourly Scheduling .............................................................................................. 25.

B. Power Production Forecasting and Data Reporting .................................................... 45.

C. Generator Regulation Service-Capacity...................................................................... 66.

VI. Compliance Filings ....................................................................................................... 101.

VII. Information Collection Statement................................................................................. 108.

VIII. Environmental Analysis .............................................................................................. 112.

IX. Regulatory Flexibility Act Analysis .............................................................................. 113.
Docket No. RM10-11-000 ii 

X. Comment Procedures....................................................................................................... 115.

XI. Document Availability ................................................................................................... 119.

Regulatory Text 

Appendix A: List of Short Names of Commenters on the Federal Energy Regulatory 

Commission’s Notice of Inquiry on Integration of Variable Energy Resources—Docket 

No. RM10-11-000, January 2010 

Appendix B: Proposed inserts to the Pro Forma Open Access Transmission Tariff 

Appendix C: Proposed inserts to the Pro Forma Large Generator Interconnection 

Agreement 
133 FERC ¶ 61,149 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

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

NOTICE OF PROPOSED RULEMAKING 

(November 18, 2010) 

I. Introduction

1. In this Notice of Proposed Rulemaking (Proposed Rule), the Federal Energy 

Regulatory Commission (Commission) proposes reforms to the pro forma Open Access 

Transmission Tariff (OATT) that derive from the Integration of Variable Energy 

Resources Notice of Inquiry.1

 The Commission initiated that inquiry to obtain 

information on barriers to the integration of variable energy resources (VER)2

 and on the 

current state of VER integration in various regions of the country. Not unexpectedly, 

commenters indicate that VER presence is not uniform throughout the country. 

Commenters also describe their experiences integrating VERs and the on-going industry 

 1 Integration of Variable Energy Resources, 130 FERC ¶ 61,053 (2010) 

(Integrating VERs NOI). 

2

 For the purpose of this proceeding, the term variable energy resource (VER) 

refers to an electric generating facility that is characterized by an energy source that: 

(1) is renewable; (2) cannot be stored by the facility owner or operator; and (3) has 

variability that is beyond the control of the facility owner or operator. This includes, for 

example, wind, solar thermal and photovoltaic, and hydrokinetic generating facilities. 
Docket No. RM10-11-000 - 2 - 

efforts designed to address issues posed by increasing numbers of VERs. Many of these 

industry efforts are significant in scope and have the potential to address issues 

confronting regions where large concentrations of VERs are located.3

 Accordingly, in 

the Proposed Rule, the Commission has decided to propose a limited set of reforms to 

existing operational procedures that we preliminarily find to be unduly discriminatory 

and leading to unjust and unreasonable rates for transmission service. Specifically, the 

Proposed Rule addresses transmission scheduling practices, VER power production 

forecasts, and the recovery of capacity charges associated with generator imbalance 

service (i.e., generator regulation service). 

2. In Order No. 890, the Commission made several reforms to the pro forma OATT, 

recognizing that the mix of generation resources on the system was changing and that not 

all generation resources were similarly situated.4

 The Commission recognized that 

intermittent resources, such as wind power, have a limited ability to control their output, 

and that this limitation supports tailoring certain requirements to the special 

 3

 See, e.g., Joint Initiative at 1-12 (describing collaborative efforts in the Western 

Interconnection for high-value and cost-effective regional products involving increased 

coordination among different transmission providers), SMUD at 8-12 (describing 

SMUD’s participation in regional efforts in California and the Northwest), ISO/RTO 

Council at 12-18 (discussing ISO/RTO efforts to develop and incorporate VER 

forecasting into their system operations). 

4 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241, at P 5, order on reh’g, Order No. 890-A, 

FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 FERC 

¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on 

clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009). 
Docket No. RM10-11-000 - 3 - 

circumstances presented by this type of resource.5

 Similarly, the Commission 

preliminarily finds that the practice of hourly scheduling, the lack of VER power 

production forecasting, and the lack of a clear mechanism to recover the cost of providing 

generator regulation service may be contributing to undue discrimination and unjust and 

unreasonable rates in light of the entry and increasing presence of VERs on the 

transmission grid. 

3. In this Proposed Rule, the Commission proposes the following three reforms: 

(1) amend the pro forma OATT to require intra-hourly transmission scheduling; 

(2) amend the pro forma Large Generator Interconnection Agreement to incorporate 

provisions requiring interconnection customers whose generating facilities are VERs to 

provide meteorological and operational data to public utility transmission providers for 

the purpose of improved power production forecasting; and (3) amend the pro forma

OATT to add a generic ancillary service rate schedule, Schedule 10—Generator 

Regulation and Frequency Response Service, in which public utility transmission 

providers will offer to provide regulation service for transmission customers using 

transmission service to deliver energy from a generator located within a public utility 

transmission provider’s balancing authority area. The Commission recognizes that as the 

number of VERs increases, public utility transmission providers and their customers will 

 5

 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 - 4 - 

need processes and tools to manage the changing nature of generation resources on the 

transmission grid. As such, the Commission believes the reforms proposed herein will 

address some of the barriers to the integration of VERs by remedying operational and 

other challenges that may be causing undue discrimination and increased costs ultimately 

borne by consumers. 

4. Specifically, the Commission preliminarily finds that requiring transmission 

customers to adhere to hourly schedules may be unduly discriminatory and result in the 

inefficient use of transmission and generation resources to the detriment of consumers. 

The Commission also preliminarily finds that a lack of VER power production forecasts 

may unnecessarily increase the volume of regulation reserves deployed by a public utility 

transmission provider, resulting in rates that are unjust and unreasonable, and that a 

public utility transmission provider currently lacks the means by which to require VERs 

to provide it with basic information on meteorological and operational conditions which 

can be used to develop VER power production forecasts. Finally, although the 

Commission contemplated a case-by-case approach to generator regulation service in 

Order No. 890,6

 the increased interest as evidenced by commenters and the number of 

Commission filings related to this service has led us to consider a generic approach to the 

provision of generator regulation service, such as the one proposed here. 

 6

 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 690. 
Docket No. RM10-11-000 - 5 - 

5. Taken together, these proposed reforms mean: VERs and other resources will be 

able to adjust schedules within the operating hour, allowing public utility transmission 

providers to commit fewer generation and non-generation resources to provide reserves; 

public utility transmission providers will have better meteorological and operational 

information from interconnection customers whose generating facilities are VERs and 

will be able to use this information to develop power production forecasts for use in 

operating their systems, thus mitigating the volume of regulation reserves they deploy; 

and public utility transmission providers will have a generic schedule from which to 

recover the costs of providing generator regulation service, and customers and other 

market participants will know the cost of such service. These proposed reforms are 

intended to ensure that the requirements set forth in the pro forma OATT result in the 

provision of Commission-jurisdictional services at rates that are just and reasonable, and 

not unduly discriminatory or preferential, consistent with the Commission’s 

responsibilities under sections 205 and 206 of the Federal Power Act (FPA).7

II. Background

6. In 1996, the Commission issued Order No. 888, which found that it was in the 

economic interest of public utility transmission providers to deny transmission service or 

to offer transmission service on a basis that is inferior to that which they provide to 

 7

 16 U.S.C. 824d, 824e. 
Docket No. RM10-11-000 - 6 - 

themselves.8

 Concluding that unduly discriminatory and anticompetitive practices 

existed in the electric industry and that, absent Commission action, such practices would 

increase as competitive pressures in the industry grew, the Commission in Order No. 888 

required all public utility transmission providers that own, control, or operate 

transmission facilities used in interstate commerce to have on file an open access, 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 

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

uniformly applicable interconnection agreement for large generator interconnections.9

 

 8 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities 

and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,682 

(1996), order on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, 

Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC 

¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group 

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

(2002). 

9 Standardization of Generator Interconnection Agreements and Procedures, 

Order No. 2003, FERC Stats. & Regs. ¶ 31,146, at P 11 (2003), order on reh’g, Order 

No. 2003-A, FERC Stats. & Regs. ¶ 31,160, order on reh’g, Order No. 2003-B, FERC 

Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003-C, FERC Stats. & Regs. 

¶ 31,190 (2005), aff’d sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 

475 F.3d 1277 (D.C. Cir. 2007). 
Docket No. RM10-11-000 - 7 - 

Accordingly, the Commission adopted standard procedures (the Large Generator 

Interconnection Procedures or LGIP) and a standard agreement (the Large Generator 

Interconnection Agreement or LGIA) for the interconnection of generation resources 

greater than 20 MW.10 These reforms were designed to minimize opportunities for undue 

discrimination and expedite the development of new generation, while protecting 

reliability and ensuring that rates are just and reasonable.11 

8. In Order No. 2003-A, the Commission explained that the interconnection 

requirements adopted in Order No. 2003 were based on the needs of traditional 

synchronous generators and that a different approach may be appropriate for generators 

relying on newer technology.12 The Commission therefore exempted wind resources 

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

for the inclusion of interconnection standards specific to newer technologies.13 

Subsequently, in Orders Nos. 661 and 661-A, the Commission adopted a package of 

interconnection standards applicable to large wind generators for inclusion in Appendix 

G of the LGIA.14 

 10 Id. 

11 Id. 

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

13 Id.

14 Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs. ¶ 31,186 

(2005), order on reh’g, Order No. 661-A, FERC Stats. & Regs. ¶ 31,198 (2005). 
Docket No. RM10-11-000 - 8 - 

9. More recently, in recognition of the evolving energy industry and in a further 

effort to remedy the potential for undue discrimination, the Commission revised and 

updated the pro forma OATT in Order No. 890.15 Among other things, the Commission 

adopted a set of transmission planning principles,16 created a new pro forma ancillary 

service schedule designed to address energy imbalances caused by generators,17 and 

instituted a new conditional firm transmission product.18

10. As these and other reforms illustrate, the Commission routinely evaluates the 

effectiveness of its regulations and policies in light of changing industry conditions. 

Consistent with this practice, the Commission issued the Integrating VERs NOI on 

January 21, 2010 to better understand the challenges associated with the large-scale 

integration of VERs on the interstate transmission system and the extent to which 

existing operational practices may be imposing barriers to their integration.19 The 

Commission explained that the changing characteristics of the nation’s generation 

 15 Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-

A, FERC Stats. & Regs. ¶ 31,261, order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299,

order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, Order 

No. 890-D, 129 FERC ¶ 61,126. 

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

17 Id. P 663-72. 

18 Id. P 911-15. 

19 Integrating VERs NOI, 130 FERC ¶ 61,053 at P 9. 
Docket No. RM10-11-000 - 9 - 

portfolio compelled a fresh look at existing policies and practices.20 Therefore, in the 

Integrating VERs NOI, the Commission sought comments on the following subject areas: 

(1) power production forecasting, including specific forecasting tools and data and 

reporting requirements; (2) scheduling practices, flexibility, and incentives for accurate 

scheduling of VERs; (3) forward market structure and reliability commitment processes; 

(4) balancing authority area coordination and/or consolidation; (5) suitability of reserve 

products and reforms necessary to encourage the efficient use of reserve products; 

(6) capacity market reforms; and (7) redispatch and curtailment practices necessary to 

accommodate VERs in real time.21 

11. The response from commenters was significant, with more than 135 entities 

submitting comments that responded to some or all of the questions posed by the 

Commission.22 A number of commenters, especially from the VER industry, argue that 

there is a clear need for the Commission to undertake basic reforms, and they urge the 

Commission to do so.23 At the same time, a common theme expressed by a number of 

commenters is that different parts of the country face different challenges associated with 

 20 Id.

21 Id. P 12. 

22 See Appendix A. 

23 AWEA at 2; Iberdrola at 8-10; NextEra 2-8. 
Docket No. RM10-11-000 - 10 - 

the integration of VERs.24 For example, commenters in the Northwest tend to focus on 

the difficulties posed by the deployment of wind resources,25 whereas commenters in the 

Southwest tend to focus on the difficulties posed by the deployment of solar resources.26 

Further still, commenters in the South explain that in many areas the geography and 

regional conditions are less suitable to the development of significant wind and solar 

resources.

27 Commenters therefore express a need for flexibility in responding to these 

challenges and urge the Commission to take this need into account in crafting any 

proposed rules.28 

III. The Need for Reform

12. The Commission preliminarily finds that the package of reforms proposed herein 

is needed to protect against unjust and unreasonable rates, terms, and conditions and 

undue discrimination in the provision of Commission-jurisdictional services. 

Specifically, the Commission is proposing to reform the pro forma OATT to ensure that 

the services provided are not structured in an unduly discriminatory manner, that public 

utility transmission providers have access to needed information to facilitate the 

integration of VERs, and that transmission customers have a clear understanding of the 

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

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

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

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

28 Southern at 4-10; EEI at 2; ColumbiaGrid at 4-5. 
Docket No. RM10-11-000 - 11 - 

determination of and obligations for the provision of ancillary services.29 The 

Commission believes that this set of proposed reforms represents a reasonable foundation 

upon which public utility transmission providers will be well-positioned to manage 

system variability associated with increased numbers of VERs. The Commission 

anticipates that the proposed operational and pricing reforms will result in a more 

efficient utilization of all generation, non-generation,30 and transmission resources and 

lay the basis for continued development, including the possibility of innovative solutions, 

such as efforts by the Joint Initiative in the West. 

13. As noted in the Integrating VERs NOI, the composition of the electric generation 

portfolio is changing. VERs are making up an increasing percentage of new generating 

 29 As part of this Proposed Rule, the Commission is also proposing a minor 

revision to 18 C.F.R. 35.28. To date, when amending its regulations concerning 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 

(as indicated by, e.g., proposed regulatory text included in another recently issued Notice 

of Proposed Rulemaking: Transmission Planning and Cost Allocation by Transmission 

Owning and Operating Public Utilities, 131 FERC ¶ 61,253 (2010)). This process is 

increasingly cumbersome. Thus as part of this Proposed Rule, the Commission proposes 

to no longer explicitly reference, by name, prior Commission rulemaking proceedings 

promulgating and amending the pro forma OATT in its regulations. Likewise, the 

Proposed Rule includes a similar change with respect to a public utility transmission 

provider’s obligation to have standard generator interconnection procedures and 

agreements and standard small generator interconnection procedures and agreements on 

file with the Commission. 

30 See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 888 (modifying 

Schedules 2,3,4,5,6, and 9 of the pro forma OATT to indicate that the ancillary services 

provided in those rate schedules may be provided by generating units as well as other 

non-generation resources such as demand response where appropriate). . 
Docket No. RM10-11-000 - 12 - 

capacity being brought on-line—in 2009, new wind generating capacity rose to 9,994 

MW, or 39 percent of all newly installed generating capacity, bringing total wind 

generating capacity to more than 35,000 MW.31 In addition to this existing capacity, 

another 85 GW of wind generating capacity has been proposed to be online by the end of 

2012.32 The amount of new solar generating capacity also has increased in recent years, 

adding 351 MW in 2008 and 481 MW in 2009, bringing the total solar generating 

capacity to more than 2,000 MW.33

14. The Commission expects the number of VERs, both in real numbers and as a 

percentage of total generation capacity, to continue to grow. Indicators of this anticipated 

growth are suggested by the significant number of public policies, both at the state and 

federal levels, encouraging the development of VERs. In the Integrating VERs NOI, the 

Commission noted that as of December 2009, 30 states and the District of Columbia had 

 31 Ryan Wiser & Mark Bolinger, Lawrence Berkeley National Laboratory, 2009 

Wind Technologies Market Report 3-5 (2010), available at

http://www1.eere.energy.gov/windandhydro/pdfs/2009_wind_technologies_market_repor

t.pdf. 

32 Div. of Energy Market Oversight, Fed. Energy Regulatory Comm’n, 2009 State 

of the Markets Report (2010), available at http://www.ferc.gov/market-oversight/st-mktovr/som-rpt-2009.pdf. 

33 Solar Energy Industries Ass’n, US Solar Industry Year in Review 2009, at 2, 

available at http://seia.org/galleries/defaultfile/2009%20Solar%20Industry%20Year%20in%20Review.pdf. 
Docket No. RM10-11-000 - 13 - 

a renewable portfolio standard.34 Moreover, federal tax policies that provide incentives 

to the development of renewable generation facilities have been in place for a number of 

years. For example, the federal production tax credit, which has been in effect 

intermittently since the early 1990s, provides an inflation-adjusted credit for power 

produced from VERs and other renewable resources.35 In February 2009, the American 

Recovery and Reinvestment Act (ARRA) not only extended the production tax credit for 

a period of three additional years,36 but also instituted an investment tax credit, which 

allows developers of certain renewable generation facilities to take a 30 percent cash 

grant in lieu of the production tax credit.37 Other federal policies that provide incentives 

to renewable generation facilities include accelerated depreciation of certain renewable 

generation facilities and loan guarantee programs. 

15. The Commission has recognized this policy development, not only in this 

proceeding, but also in the Transmission Planning and Cost Allocation Proposed Rule, 

observing that “state policies to promote increased reliance on renewable energy 

 34 See Integrating VERs NOI, 130 FERC ¶ 61,053 at P 2 (citing Div. of Energy 

Market Oversight, Fed. Energy Regulatory Comm’n, Renewable Power and Energy 

Efficiency Market: Renewable Portfolio Standards 1 (2009), available at

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

35 26 U.S.C. 45. 

36 American Recovery and Reinvestment Tax Act of 2009, Pub. L. No. 111-5, sec. 

1101, 123 Stat. 115, 319 (2009). 

37 Id. sec. 1102, 123 Stat. 115, 319-20. 
Docket No. RM10-11-000 - 14 - 

resources, such as the renewable portfolio standard measures discussed above, accentuate 

the need for transmission to deliver electricity from location-constrained renewable 

energy resources to load centers.”38 The same observation is true for the operational 

reforms proposed here. Public policies that promote renewable resources accentuate the 

need for reforms to operational protocols that unduly discriminate against VERs and/or 

have the effect of maintaining rate structures that are no longer just and reasonable. 

16. As the number of VERs has increased, the Commission has received a variety of 

proposals that seek variations from the pro forma OATT and/or LGIA in order to address 

system needs resulting from the integration of VERs. In recent years, a number of public 

utility transmission providers have proposed to assess various forms of ancillary services 

charges to wind generating resources, while others have proposed revised interconnection 

standards addressing reporting requirements and additional ancillary service 

obligations.39 Consistent with many of the comments received in response to the 

Integrating VERs NOI, such filings suggest that the pro forma OATT and LGIA may 

need adjustments to address operational issues arising in response to the increased 

integration of VERs in individual balancing authority areas. 

 38 Transmission Planning and Cost Allocation by Transmission Owning and 

Operating Public Utilities, 131 FERC ¶ 61,253, at P 36 (2010) (Transmission Planning 

and Cost Allocation Proposed Rule). 

39 See, e.g., NorthWestern Corp., 129 FERC ¶ 61,116 (2009) (NorthWestern), 

order on reh’g, 131 FERC ¶ 61,202 (2010); Westar Energy Inc., 130 FERC ¶ 61,215 

(2010) (Westar); Cal. Indep. Sys. Operator Corp., 131 FERC ¶ 61,087 (2010); Puget 

Sound Energy, Inc., 132 FERC ¶ 61,128 (2010) (Puget Sound). 
Docket No. RM10-11-000 - 15 - 

17. In light of these filings, comments, and the increasing deployment of VERs on the 

nation’s transmission system, the Commission has identified reforms that it preliminarily 

finds would eliminate operational procedures that have the de facto effect of imposing an 

undue burden on VERs. The proposed reforms acknowledge that existing practices as 

well as the ancillary services used to manage system variability were developed at a time 

when virtually all generation on the system could be scheduled with relative precision 

and when only load exhibited significant degrees of within-hour variation. In proposing 

these reforms, the Commission seeks to ensure that VERs are integrated into the 

transmission system in a coherent and cost-effective manner, consistent with open access 

principles. 

18. The Commission is aware that, in many instances, issues associated with VER 

integration are highly technical in nature and can vary significantly from one region to 

the next. The Commission is also cognizant of and supports ongoing industry initiatives 

dedicated to crafting regional solutions to the challenges associated with VER 

integration. Such regional efforts include the work being conducted by the North 
Docket No. RM10-11-000 - 16 - 

American Electric Reliability Corporation (NERC) through the Integration of Variable 

Generation Task Force40 and the work of the Joint Initiative.41 As such, the reforms 

proposed here do not purport to resolve all of the challenges associated with VER 

integration, nor are they intended to undermine progress being made in various regions 

regarding VER integration. The Commission’s goal in this proceeding is simply to 

identify those basic reforms that can and should be implemented in the near term. The 

Commission believes that the reforms proposed herein can and should be implemented in 

a way that complements ongoing stakeholder proceedings. 

IV. Summary of Proposed Reforms

19. The Commission is proposing three reforms that, taken together, are designed to 

address issues confronting public utility transmission providers and VERs and to allow 

for the more efficient utilization of transmission and generation resources to the benefit 

of all customers. First, the Commission proposes to provide the transmission customer 

with the option of using more frequent transmission scheduling intervals within each 

operating hour, at 15-minute intervals, so that they may adjust their transmission 

schedules to reflect, in advance of real-time, more accurate power production forecasts, 

 40 See North American Elec. Reliability Corp., Accommodating High Levels of 

Variable Generation (2009), available at

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

41 See Joint Initiative at 3-11 (describing projects currently being developed by 

members of Columbia Grid, Northern Tier Transmission Group and WestConnect such as 

an Intra-Hour Transaction Accelerator Platform and a Dynamic Scheduling System). 
Docket No. RM10-11-000 - 17 - 

load profiles, and other changing system conditions. At the same time, this proposed 

reform will enable public utility transmission providers and other entities to manage the 

system’s variability more effectively and, over time, rely less on ancillary services and 

more on the flexibility of generation and non-generation resources. 

20. Second, the Commission proposes to require public utility transmission providers 

to amend their pro forma LGIAs to incorporate provisions requiring interconnection 

customers whose generating facilities are VERs to provide certain meteorological and 

operational data to public utility transmission providers to facilitate public utility 

transmission providers’ development and deployment of VER power production 

forecasting tools. Under the LGIA provisions proposed here, the interconnection 

customer whose generating facility is a VER would only be required to provide such data 

in the instance where the interconnecting public utility transmission provider is 

developing and/or deploying VER power production forecasting tools. 

21. Third, the Commission proposes to add a generic ancillary service rate schedule to 

the pro forma OATT through which a public utility transmission provider must offer 

generator regulation service, to the extent it is physically feasible to do so from its 

resources or from resources available to it, to transmission customers using transmission 

service to deliver energy from a generator located within the transmission provider’s 

balancing authority area. Under this proposed rate schedule, a public utility transmission 

provider will have the opportunity to recover reserve service costs associated with 

management of supply-side variability. In Order No. 890, the Commission took a caseby-case approach to filings by public utility transmission providers seeking to recover the 
Docket No. RM10-11-000 - 18 - 

costs of additional regulation reserves associated with providing generator imbalance 

service.42 This existing policy, however, has led to uncertainty and allows the potential 

for undue discrimination. To prevent this uncertainty and potential undue discrimination, 

we believe it is appropriate now to propose a generic generator regulation reserve rate 

schedule that will delineate the rights and obligations of public utility transmission 

providers and customers with respect to the provision of this service. 

22. Additionally, the Commission is proposing guidelines under which public utility 

transmission providers may assess generator regulation reserve charges to transmission 

customers. Such charges must be established based on traditional cost causation 

principles. To the extent a public utility transmission provider proposes to require 

transmission customers who are delivering energy from VERs to purchase, or otherwise 

account for, a different volume of generator regulation reserves than it proposes to charge 

transmission customers delivering energy from other generating resources, such differing 

volumes must be shown to be commensurate with the variability that VERs exhibit on the 

transmission provider’s system. Furthermore, the public utility transmission provider 

 42 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 689 n.401, order on reh’g, 

Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 313. More recently, the 

Commission clarified transmission providers’ obligation to offer generator regulation 

service by rejecting a transmission provider’s proposal to require VERs exporting out of 

the transmission provider’s balancing authority area to provide or arrange for their own 

generator regulation capacity. See NorthWestern, 129 FERC ¶ 61,116 at P 24 (finding 

that the proposal to disclaim the obligation to provide the capacity reserves necessary to 

providing generator imbalance service would be inconsistent with the transmission 

provider’s obligation to offer generator imbalance service set forth in the pro forma

OATT). 
Docket No. RM10-11-000 - 19 - 

must show that it has adopted measures to mitigate the total amount of regulation reserve 

necessary to manage the variability through the implementation of VER power 

production forecasting and intra-hourly scheduling. This mitigation requirement will 

help to ensure that the rates for this service are just and reasonable. 

23. Through these three proposals, the Commission seeks to reform operational 

protocols that present barriers to the integration of VERs and to ensure the cost of 

integrating new resources, such as VERs, are not unnecessarily inflated by inappropriate 

systems and processes. While the proposed reforms focus on discrete operational 

protocols, they are integrally related and should be understood as complementary parts of 

a package. The Commission believes this set of reforms will help to level the playing 

field for all types of resources, provide much-needed clarification as to the roles and 

responsibilities of public utility transmission providers and transmission customers, and 

bring greater transparency and efficiency to existing system operations. As described in 

more detail below, the Commission believes that these proposed rules are necessary to 

remedy undue discrimination in existing transmission system operations and to ensure 

that rates for Commission-jurisdictional services are just and reasonable. 

24. As should be clear from the scope of this Proposed Rule, the Commission is not 

proposing to address the additional issues identified in the Integrating VERs NOI at this 

time. Upon review of the comments, the Commission believes that further study of many 

issues identified in the Integrating VERs NOI is required. In addition, a number of 
Docket No. RM10-11-000 - 20 - 

parties are actively developing solutions to address issues raised in the Integrating VERs 

NOI.43 Therefore, in keeping with the suggestion of a number of commenters to allow 

individual regions to continue to develop solutions to the challenges unique to their 

characteristics and resources, and in recognition of commenters who seek Commission 

engagement on these issues, the Commission proposes to instruct its staff to monitor and 

conduct outreach with industry stakeholders to keep abreast of developments. 

V. Proposed Reforms

A. Intra-hourly Scheduling

25. Outside of regions that have an RTO or ISO, resources typically schedule 

transmission service on an hourly basis, and adjustments to such schedules are permitted 

during the hour only for emergency situations that threaten reliability.44 In the 

 43 See, e.g., Joint Initiative at 7-12 (explaining ongoing efforts in the West to 

develop a dynamic scheduling system and intra-hour transaction accelerator platform to 

facilitate transactions among balancing authorities); ISO/RTO Council at 44 (indicating 

that ISOs and RTOs have begun to integrate centralized forecasting into reliability 

commitment processes); NERC, Integration of Variable Generation Task Force, 2009-

2011 Work Plan (2009), available at

http://www.nerc.com/docs/pc/ivgtf/IVGTF_Work_%20Plan_111309.pdf (detailing ongoing efforts to establish mechanisms to calculate the capacity associated with VERs). 

See also Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 1626-27 (requiring 

transmission providers to use an OASIS template that will be developed by the North 

American Energy Standards Board to post information concerning curtailments, 

including the circumstances and events leading to a firm service curtailment, specific 

customers and services curtailed, and the duration of the curtailment). 

44 Section 13.8 of the pro forma OATT requires transmission customers to 

schedule use of firm point-to-point transmission service by 10:00 a.m. the day prior to 

operation. That section also gives the transmission provider the discretion to accept 

schedule changes no later than 20 minutes prior to the operating hour. 
Docket No. RM10-11-000 - 21 - 

Integrating VERs NOI, the Commission noted that existing scheduling practices were 

designed at a time when virtually all generation on the system could be scheduled with 

relative precision.45 The Commission also acknowledged that, with increasing numbers 

of VERs, system operators appear to be relying more on reserves, such as regulation 

reserves, to balance the variation in energy output from VERs.46 

26. The Commission further explained that because transmission schedules are 

typically set 20-30 minutes ahead of the hour, the forecast of a VER’s output (upon 

which its schedule is based) may be 90 minutes old by the end of the operating hour.47 

As a result, because of a resource’s limited ability to adjust its schedules during the hour, 

the operational flexibility of all resources on the transmission provider’s system may not 

be utilized.48 

27. Therefore, the Commission sought to explore whether the retention of existing 

transmission scheduling practices had caused the rates for reserves to become unjust and 

unreasonable by inhibiting the ability of VERs to establish operationally-viable schedules 

and preventing public utility transmission providers from utilizing the flexibility of their 

systems. More specifically, the Commission sought to explore whether greater 

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

46 Id.

47 Id. P 19. 

48 Id.
Docket No. RM10-11-000 - 22 - 

transmission scheduling flexibility, such as intra-hour scheduling or other improvements 

in the scheduling procedures, might offer the potential for greater efficiency in 

dispatching all resources. For instance, the Commission noted the potential for more 

efficient dispatch if the magnitude of schedule deviations could be reduced, better 

anticipated, and/or planned for more precisely.49 

1. Comments

28. Most commenters recognize the benefits and support the implementation of some 

form of intra-hour transmission scheduling. AWEA states that shorter scheduling 

intervals will allow generators to provide inexpensively much of the flexibility that is 

currently being provided by expensive regulation reserves.50 AWEA points out that the 

Avista Wind Integration Study similarly found wind integration costs would be reduced 

by 40-60 percent by moving from hourly to intra-hourly dispatch intervals.51 

Additionally, AWEA asserts that Bonneville has publicly stated that wind integration 

costs on its system would be reduced by 80 percent by moving from hourly schedules to 

 49 Id. P 18-21. 

50 AWEA at 38 (citing M. Milligan & B. Kirby, Impact of Balancing Area Size, 

Obligation Sharing, and Ramping Capability on Wind Integration, 27-29 (2007), 

available at

http://www.nrel.gov/wind/systemsintegration/pdfs/2007/milligan_wind_integration_impa

cts.pdf). 

51 AWEA at 20 (citing Avista Corp., Wind Integration Study (2007), available at

http://www.uwig.org/AvistaWindIntegrationStudy.pdf). 
Docket No. RM10-11-000 - 23 - 

intra-hourly schedules.52 Bonneville states that intra-hour scheduling has the potential to 

help better manage the costs and operational impacts of VER generator imbalances.53 

29. WECC explains that shorter scheduling intervals allow system operators to 

manage the integration of VERs more efficiently, because they permit the use of forecasts 

that are closer to the operating time frame, and are therefore more accurate.54 EEI states 

that for regions with significant amounts of VERs, it appears that shorter intervals would 

allow system operators to manage VER ramp events55 and variability, provide more 

accurate scheduling, reduce the reliance on regulating reserves and make it easier to meet 

NERC CPS-2.56 NERC claims that while additional system flexibility can come from 

many sources, such as the availability of flexible conventional resources and nonconventional resources such as storage and demand response programs, an additional 

contributor to greater system flexibility includes shorter scheduling intervals, for both 

 52 AWEA at 20 (citing Presentation by Bart McManus, Bonneville. Large Wind 

Integration Challenges and Solutions for Operations/System Reliability at slide 26 

(Oct. 2008), available at http://www.uwig.org/Denver/McManus.pdf) (stating 10 minute 

schedule changes would solve approximately 80% of the issues Bonneville is 

anticipating). 

53 Bonneville at 6. 

54 WECC at P 6. 

55 Ramp events are instances where the generating facility experiences a 

significant change in electrical output. 

56 EEI at 9. 
Docket No. RM10-11-000 - 24 - 

within a balancing authority area and between balancing authority areas.57 Joint 

Initiative states that allowing transmission customers to schedule transactions within an 

operating hour increases operating flexibility for VERs and the rest of the system.58 

NERC claims that the ideal scheduling increments to achieve optimum flexibility while

still meeting relevant reliability requirements may be between five and fifteen minutes; 

however, this depends on system characteristics, the type of VERs present on the system, 

and the level of VER penetration.59

 

30. AWEA argues that hourly scheduling practices have a much greater negative 

impact on VERs than on traditional dispatchable resources and that it is within the 

Commission’s statutory duty to address these issues of discrimination.60 AWEA notes 

that shorter scheduling intervals will yield significant benefits even on transmission 

systems without wind energy, as there is significant intra-hour variability in load, as well 

as in the output of non-VER resources when they experience forced outages or otherwise 

fail to provide their scheduled output.61 AWEA also contends that moving to shorter 

dispatch intervals will actually improve power system reliability by freeing up additional 

57 NERC at 16. 

58 Joint Initiative at 3. 

59 NERC at 17-18. 

60 AWEA at 16. 

61 Id. at 38. 
Docket No. RM10-11-000 - 25 - 

system flexibility that is currently underutilized.62 Iberdrola argues that the Commission 

should modify its pro forma OATT to require, at a minimum, intra-hourly scheduling of 

generation, explaining that intra-hour scheduling will improve VER scheduling accuracy 

and reduce VER integration costs.63 Southern California Edison argues that the 

Commission should ensure that new scheduling tools, such as half-hour scheduling 

intervals, are available, as these could help reduce forecast errors, and in turn, result in 

optimal transmission utilization, market efficiency, and system reliability.64 Southern 

California Edison also explains that, because it does not expect reliability issues to arise 

from scheduling rule changes, NERC Reliability Standards will require minimal or no 

changes.65

31. Many commenters, however, seek the flexibility to develop regional solutions 

without a Commission mandate that they be required to do so. The common reason given 

for this view is that each region has a unique mix of conventional generation resources 

and VERs, and each region should be allowed to explore and coordinate its own 

scheduling practices to suit its unique system needs through stakeholder processes. For 

example, EEI states that in light of the variation in market structures and rules throughout 

 62 Id. at 40. 

63 Iberdrola at 10. 

64 Southern California Edison at 10-11. 

65 Southern California Edison at 12. 
Docket No. RM10-11-000 - 26 - 

the country, it is unlikely that any single scheduling practice will suit all regions. 66 EEI 

argues that the Commission should allow each region to explore its own flexible 

scheduling options and provide policy guidance that encourages flexible scheduling 

practices to the maximum extent possible.67 Bonneville argues that mandating intra-hour 

scheduling or standardizing national practices is premature.68 The ISO/RTO Council 

supports moving toward intra-hour scheduling across the inter-ties for purposes of VER 

integration where warranted by system needs.69

32. Additionally, several of the commenters that oppose a Commission mandate to 

implement intra-hour scheduling cite reform efforts that are already underway. For 

example, the Joint Initiative describes its development of model intra-hour transmission 

purchase and scheduling business practices in the Western Interconnection.70 The Joint 

Initiative also explains that a number of utilities in the Northwest have begun to 

implement these practices to one degree or another.71 SMUD points out that the Western 

Systems Power Pool currently seeks to develop two new service schedules that will 

 66 EEI at 8. 

67 Id. at 9. 

68 Bonneville at 44. 

69 ISO/RTO Council at 36. 

70 Joint Initiative at 4. 

71 Id. at 5-6 (citing sub-hourly scheduling initiatives by the following: NV 

Energy, PacifiCorp, Bonneville, Puget, Portland General Electric, Avista Corp., Seattle 

City Light, Chelan County PUD, Grant County PUD, and Tacoma Power). 
Docket No. RM10-11-000 - 27 - 

accommodate VERs through the provision of reserve services and intra-hour 

supplemental energy. For this reason, SMUD argues that the Commission should avoid 

taking actions where industry efforts are in progress to cost-effectively achieve similar 

goals, particularly when those efforts are further taking into account regional 

characteristics.72

33. Commenters generally recognize that the implementation process is not without 

some costs. AWEA states that the cost of transitioning to intra-hourly dispatch is quite 

modest and the bulk of these costs are up-front expenditures while the benefits of making 

the transition will be realized in perpetuity.73 AWEA explains that the costs associated 

with the transition to an intra-hourly dispatch include: (1) modifications of 

dispatch/energy management and NERC e-Tag systems in order to accommodate intrahour schedules/settlements, (2) OATT revisions necessary to accommodate transmission 

reservations for periods of less than a full clock hour, and (3) possible staffing increases 

to handle the greater number of transactions.74 

34. Entergy states that it moved from hourly scheduling to twenty-minute anytimescheduling several years ago.75 According to Entergy, no changes to the OATT, e-Tag or 

 72 SMUD at 20. 

73 AWEA at 39. 

74 Id.

75 Entergy at 2. 
Docket No. RM10-11-000 - 28 - 

NERC rules were required.76 Entergy states that its scheduling systems were 

significantly modified to implement this additional flexibility, but such changes have 

proven to be manageable to date. Entergy cautions that if intra-hour scheduling is 

mandated, the burden on the system operators may increase, such as when there are 

reliability issues on the system.77 Entergy explains that at these times, system operators 

would have to handle intra-hour schedules and reliability issues simultaneously.78 

Therefore, Entergy asks the Commission to proceed carefully and consider differences 

among balancing authority areas, in terms of software, manpower, and scheduling work 

load, before mandating intra-hour scheduling.79 Similarly, Northwestern argues that 

system automation will be necessary to allow much greater number of schedules and 

transmission service requests to be processed without impacting reliability.80 National 

Rural Electric Cooperative Association (NRECA) claims that a number of NERC 

 76 Id.

77 Id.

78 Id.

79 Id.

80 NorthWestern at 14. 
Docket No. RM10-11-000 - 29 - 

standards would need to be reviewed to determine the impacts of a move towards flexible 

scheduling.81 

35. Smaller public utility transmission providers highlight challenges with respect to 

their size and explain that the implementation of intra-hour scheduling may be infeasible 

for certain entities. NRECA indicates that for smaller systems, implementation of intrahour scheduling would be a significant additional burden and could require substantial 

costs in software modification.82 NRECA explains that while changes to infrastructure 

required for trading may be absorbed by large entities, smaller cooperatives would be 

affected disproportionately because of their inability to spread the costs over the large 

volume of trade.83 NRECA claims that in any cost-benefit analysis, it is less likely that 

smaller entities will benefit, even over time, especially where they lack a large customer 

base, which is the case for many rural electric cooperatives.84 Consequently, NRECA 

contends that intra-hour scheduling is simply infeasible for some of its members at this 

time.85 

 81 NRECA at 30 (citing BAL (Resource and Demand Balancing), INT 

(Interchange Scheduling and Coordination), IRO (Interconnection Reliability Operations 

and Coordination), and MOD (Modeling, Data, and Analysis) Standards). 

82 NRECA at 28. 

83 Id. at 29. 

84 Id. 

85 Id. 
Docket No. RM10-11-000 - 30 - 

36. Finally, some commenters oppose the implementation of intra-hour scheduling for 

their regions regardless of cost or whether the Commission allows for regional 

differences. Generally, these commenters base their objections on two grounds. First, 

commenters under the impression that the intra-hour scheduling would be available only 

to transmission customers using VERs argue that it would be unfair to afford scheduling 

opportunities to one class of transmission customers and not others, such as those 

utilizing conventional resources. Southern argues that there should not be any unique or 

special scheduling protocols applicable to only certain types of generation.86 Second, 

commenters argue that the responsibility for scheduling efficiency should fall on VERs. 

These commenters generally argue that VERs should be required to maintain the 

accuracy of their schedules and should not expect public utility transmission providers to 

change scheduling practices that have worked in the past. Altresco states that 

maintaining scheduling practices is essential to the reliability of the grid, and that VERs 

should take responsibility for the reliability impact of the variability of their resource.87 

Southern state that all generators (including VERs) should be responsible for providing 

accurate schedules and that the risk and responsibility for forecasting availability should 

 86 Southern at 11. 

87 Altresco at 5-6. 
Docket No. RM10-11-000 - 31 - 

always be the generator’s responsibility and should not be shifted to the public utility 

transmission provider or system operator.88

2. Commission Discussion

37. The Commission preliminarily finds that hourly transmission scheduling protocols 

are no longer just and reasonable and may be unduly discriminatory as the default 

scheduling time periods required by the pro forma OATT. Specifically, we preliminarily 

find that existing hourly transmission scheduling protocols expose transmission 

customers to excessive or unduly discriminatory generator imbalance charges and are 

insufficient to provide system operators with the flexibility to manage their system 

effectively and efficiently. Therefore, the Commission proposes to amend sections 13.8 

and 14.6 of the pro forma OATT to provide transmission customers the option to 

schedule transmission service on an intra-hour basis, at intervals of 15 minutes.89 The 

Commission notes that the proposed 15-minute interval is consistent with the ideal time 

increments (i.e., 5 to 15 minutes) recommended by NERC to achieve greater flexibility 

while still meeting relevant reliability requirements.90 Additionally, the Commission 

notes that many commenters claim that shorter scheduling intervals may enhance system 

 88 Southern at 11. 

89 The Commission’s proposed reform allows for intra-hour scheduling 

adjustments; it does not propose changes to the hourly transmission service reservations 

provided in the OATT. 

90 NERC at 17-18. 
Docket No. RM10-11-000 - 32 - 

reliability.91 As such, we do not believe, as NRECA suggests, that an independent 

review of NERC standards is necessary to making this proposed reform. Howev

Commission seeks comment on the issue to ensure that there is no inconsistency among 

relevant NERC standards and the proposed intra-hour scheduling tariff reform. 

er, the 

 

38. As explained above, hourly transmission scheduling protocols were developed at a 

time when virtually all generation on the system could be scheduled with relative 

precision.92 The resulting net system variability, i.e., the net variation between the load 

and generator imbalance, was such that hourly scheduling protocols were sufficient to 

maintain system balance. As higher amounts of VERs interconnect with the grid, these 

hourly scheduling protocols make it increasingly difficult for public utility transmission 

providers and balancing authorities to maintain system balance.93 In order to 

accommodate any increased intra-hour supply-side variability caused by increasing 

numbers of VERs, public utility transmission providers in areas without organized realtime energy markets rely on reserve services, which are provided under a number of 

existing ancillary service rate schedules.94

91 NERC at 20, AWEA at 40, EEI at 29, Southern California Edison at 11-12, 

CalWEA at 7, Pacific Gas and Electric at 6, NaturEner at 11, and Wärtsilä at 7. 

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

93 Bonneville at 45. 

94 Order No. 888, FERC Stats. & Regs. at 31,703-704. 
Docket No. RM10-11-000 - 33 - 

39. The Commission believes that it is unduly discriminatory to perpetuate the 

practice for resources to match hourly transmission schedules, especially when the output 

of a resource (such as a VER) fluctuates beyond its reasonable control. Moreover, the 

Commission believes that requiring public utility transmission providers to procure 

ancillary services to manage generating resources’ deviations across an operating hour is 

an inefficient and burdensome operating protocol with the potential to result in unjust and 

unreasonable rates. Therefore, in order to prevent excessive costs attributable to reserve 

services, an over-reliance on these reserve services in maintaining overall system 

balance, and undue discrimination against VERs, the Commission proposes to reform 

existing transmission scheduling practices. Under this proposed reform, all transmission 

customers will have the opportunity to take advantage of the shorter scheduling intervals 

and submit accurate intra-hour schedules, thereby mitigating the amount of regulation 

reserves or other ancillary services public utility transmission provider will need to 

procure. 

40. The Commission expects this proposed reform to benefit many types of entities. 

For example, with shorter scheduling intervals, public utility transmission providers 

should have greater assurance that the schedules submitted by transmission customers 

using VERs are accurate. Therefore, these public utility transmission providers will be in 

a better position to anticipate and respond to fluctuations in VER energy production. In 

this way, the public utility transmission provider will be able to rely more on planned 

scheduling and dispatch procedures in maintaining overall system balance and rely less 

on reserves. At the same time, transmission customers delivering energy from VERs will 
Docket No. RM10-11-000 - 34 - 

be in a reasonable position to match their scheduled output with actual output, thereby 

managing their exposure to generator imbalance charges. Likewise, transmission 

customers delivering energy from energy constrained resources, such as flow-limited 

hydro generators, emission-limited thermal generators, demand response resources and 

energy storage resources will be better able to schedule transmission to reflect constraints 

in their operations. In addition, increased scheduling flexibility should help balancing 

authorities to more closely match scheduled production with actual output, which will 

enhance their ability to meet NERC Reliability Standards. 

41. Accordingly, the Commission proposes to require public utility transmission 

providers to offer all transmission customers the option to submit changes to schedules in 

an interval of 15 minutes and allow all transmission customers the option of submitting 

intra-hour schedules up to 15 minutes before the scheduling interval. While the 

Commission proposes to establish a 15-minute scheduling interval, this proposed reform 

is not intended to deter public utility transmission providers from providing transmission 

scheduling intervals that are less than the proposed 15-minute period. To the extent 

public utility transmission providers incur costs as a result of implementing this proposed 

scheduling reform, the Commission proposes to allow such costs to be recovered 

pursuant to Schedule 1 of the transmission providers’ OATTs. 

42. The Commission acknowledges that a number of public utility transmission 

providers already have begun implementing intra-hour scheduling practices, primarily 
Docket No. RM10-11-000 - 35 - 

through reforms to their business practices.95 While these individual reforms are 

important steps toward the efficient integration of VERs, the Commission believes that it 

is important to establish 15-minute scheduling periods as the default scheduling process 

among transmission providers. Because VERs tend to be located far from load centers, 

energy produced from VERs in one region is often sold to load serving entities in another 

region, requiring transmission service spanning one or more systems. The Commission 

believes that the proposed 15-minute scheduling protocols will benefit transmission 

customers delivering energy across multiple systems by allowing them to schedule 

energy on more than one system at similar intra-hour scheduling intervals that are in no 

event less than four times within the hour. In this way, the proposed 15-minute 

scheduling protocols will afford transmission customers using multiple systems the same 

flexibility as those using only one transmission system. Such intra-hour scheduling 

intervals also could lay the groundwork for the development of flexible energy and/or 

capacity products, thereby reducing the need for public utility transmission providers to 

rely on ancillary services to manage the variability of VERs. 

43. At the same time, the Commission acknowledges 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 this regard, 

 95 See Joint Initiative at 5-6 (citing sub-hourly scheduling initiatives by the 

following: NV Energy, PacifiCorp, Bonneville, Puget, Portland General Electric, Avista 

Corp., Seattle City Light, Chelan County PUD, Grant County PUD, and Tacoma Power). 
Docket No. RM10-11-000 - 36 - 

the Commission seeks comment on the best approach for implementing the intra-hour 

scheduling reforms proposed here. The Commission recognizes 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, commenters should consider any impacts on transmission 

customers scheduling across multiple systems and whether these impacts diminish the 

benefits of implementing intra-hour scheduling. 

44. Finally, several commenters point out that hardware, software, and personnel 

modifications may be required in order to implement intra-hour transmission scheduling. 

To more fully understand the modifications that this proposed reform may require, the 

Commission seeks more detailed comment on the specific hardware, software, and 

personnel changes that are necessary to implement intra-hour scheduling, any additional 

impacts on relatively small public utility transmission providers, and how to best 

facilitate this reform for small public utility transmission providers. 

B. Power Production Forecasting and Data Reporting

45. Research has shown that VERs power production forecasts are essential in 

managing the variability of VERs and, equally importantly, the use of these forecasting 

methodologies enhances economic efficiency and allows transmission providers to 
Docket No. RM10-11-000 - 37 - 

manage the operational effects of VERs on their transmission system.96 Detailed and 

timely power production forecasts are critical to reducing uncertainty regarding the 

expected level of VER power output at various points in time.97 By reducing uncertainty, 

power production forecasts give transmission providers an improved situational 

awareness of their transmission systems. These power production forecasting tools also 

provide transmission providers with the advanced knowledge of system conditions 

needed to manage the variability of VER generation through the unit commitment and 

dispatch process, rather than managing the variability through the deployment of reserve 

services, such as regulation reserves. With situational awareness of forecasted 

variability, the transmission provider and/or balancing authority can commit or decommit resources providing regulation reserves, to the extent and when they will be 

needed to maintain system reliability.98 NREL’s Western Wind and Solar Integration 

Study found that, while state-of-the-art power production forecasting for VERs may be 

imperfect, it is still beneficial to incorporate such forecasts into the existing scheduling 

and unit commitment processes. Additional research indicates that the accuracy of wind 

 96 NERC, Integration of Variable Generation Task Force, Task 2.1 Report: 

Variable Generation Power Forecasting for Operations 5 (2010), available at

http://www.nerc.com/docs/pc/ivgtf/Task2-1(5.20).pdf. 

97 Id. at 54. See also National Renewable Energy Laboratory, Eastern Wind 

Integration Study 29 (2010), available at

http://www.nrel.gov/wind/systemsintegration/pdfs/2010/ewits_final_report.pdf. 

98 NERC at 6. 
Docket No. RM10-11-000 - 38 - 

power forecasts is directly connected to the amount of balancing energy needed and 

hence the cost of wind power integration.99 In WECC alone, NREL estimates that the 

use of VER power production forecasts has the potential to reduce operating costs by up 

to 14 percent or $5 billion per year.100 

46. In SPP101 and ERCOT,102 studies have been commissioned that recommend the 

use of VER power production forecasting in unit commitment and reliability assessment 

analyses and the procurement of ancillary services. In Minnesota, research conducted in 

2006 suggested that the failure to consider probable wind generation in the day-ahead 

market could result in incorrect price signals and market inefficiencies.103

 99 Bernhard Ernst et al., Predicting the Wind, IEEE Power & Energy Mag., 

Nov.–Dec. 2007, at 78, 79, available at

http://www.awea.org/utility/pdf/04383126predicting.pdf. 

100 National Renewable Energy Laboratory, Western Wind and Solar Integration 

Study ES-18 (2010), available at

http://www.nrel.gov/wind/systemsintegration/wwsis.html. 

101 Charles River Assoc., SPP WITF Wind Integration Study 6-19 (2010), 

available at

http://www.crai.com/consultingexpertise/listingdetails.aspx?id=12091&tID=828&subtID

=0&tertID=0&fID=34&SectionTitle=Energy+%26+Environment. 

102 GE Energy, Analysis of Wind Generation Impact on ERCOT Ancillary Services 

Requirements 9-7 (2008), available at http://www.uwig.org/AttchB-ERCOT_AS_Study_Final_Report.pdf. 

103 Enernex Corporation, 2006 Minnesota Wind Integration Study 73-74 (2006), 

available at http://www.uwig.org/windrpt_vol%201.pdf. 
Docket No. RM10-11-000 - 39 - 

47. Some public utility transmission providers have already instituted forecasting 

programs that are designed to address the variability associated with VERs. In 2004, the 

Commission accepted the CAISO’s Participating Intermittent Resources Program (PIRP) 

and acknowledged the importance of centralized power production forecasting in 

reducing the barriers to VERs participation in the CAISO energy market.104 To 

effectuate this program, CAISO is provided with the real-time operational and 

meteorological data necessary to forecast VER power production over a variety of time 

periods. VERs that participate in the PIRP are required to submit a power production 

schedule, through their scheduling coordinator, consistent with the CAISO’s forecast of 

energy generation. PIRP participants are assessed a fee to defray CAISO’s cost of 

providing this forecasting service. 

48. In 2008, the Commission approved NYISO tariff revisions that implemented 

similar VER power production forecasting capabilities.105 The Commission found 

NYISO’s proposal to implement a centralized wind forecasting mechanism would allow 

it to predict the availability of wind resources more accurately and indicated that such a 

capability should reduce overall system operating costs. Similarly, both PJM and MISO 

have recognized the value of VER power production forecasting and have included in 

 104 Cal. Indep. Sys. Operator Corp., 98 FERC ¶ 61,327, order on compliance, 

99 FERC ¶ 61,309 (2002). 

105 New York Indep. Sys. Operator, Inc., 123 FERC ¶ 61,267, at P 13-14 (2008). 
Docket No. RM10-11-000 - 40 - 

their respective business practice manuals centralized VER power production forecasting 

programs and responsibilities. Xcel states that it forecasts wind generation in its service 

territory in partnership with the National Center for Atmospheric Research (NCAR) 

using enhanced, state-of-the-art wind output prediction tools.106 Xcel explains that while 

these tools require large amounts of meteorological information and turbine-level realtime operational data, migrating to this methodology has proven to be beneficial in terms 

of economics and reliability.107 

49. In light of these and other acknowledgements of the benefits associated with the 

increased use of VER power production forecasting in transmission system operations, 

the Commission sought comments in the Integrating VERs NOI on the state of VER 

power production forecasting in order to determine what additional tools and/or data may 

be necessary to incorporate increasing levels of VERs on the interstate transmission 

system.108 The Commission sought information in three general areas: (1) current VER 

power production forecasting efforts; (2) the data needed to create state-of-the-art power 

production forecasts; and (3) regulatory changes, if any, needed to incorporate power 

production forecasts into system operations. 

 106 Xcel at 3. 

107 Id.

108 Integrating VERs NOI, 130 FERC ¶ 61,053 at P 14-17. 
Docket No. RM10-11-000 - 41 - 

1. Comments

50. In response to the Integrating VERs NOI, commenters filed detailed accounts of 

the current state of VER power production forecasting, and the necessary steps to 

incorporate state-of-the-art forecasting into system operations. Argonne National Lab’s 

research indicates that increased levels of VERs will necessitate the incorporation of 

power production forecasting in unit commitment analyses to maintain system 

reliability.109 NREL adds that ignoring VER power production forecasting during the 

unit commitment process may result in the commitment of too much or too little 

generating capacity and potentially generate economic losses over time.110 NERC states 

that VER power production forecasts must be integrated into day-to-day reliability 

analyses and operations to ensure that system operators and market participants can 

create operating plans and procure necessary resources to keep supply and demand in 

balance on a real-time basis.111 NERC explains that the goal of power production 

forecasting should be to identify high-risk periods where procurement of additional 

flexibility or reserves is justified to maintain system balance and reduce the commitment 

of expensive reserves when there is little risk of them being needed for reliability.112 

 109 Argonne National Lab at 1. 

110 NREL at 9. 

111 NERC at 3. 

112 Id. at 20. 
Docket No. RM10-11-000 - 42 - 

Commenters note that, while the goal of VER power production forecasts is to use 

forecasts to make better unit commitment and reliability assessment decisions, significant 

work is needed to develop better power production forecasts and determine how best to 

incorporate those forecasts into system operational decisions.113

51. One important clarification made by commenters is the differentiation between the 

underlying Numerical Weather Prediction (NWP) models and the power production 

forecasts used to estimate wind and solar plant power output. While government 

agencies like the National Oceanic and Atmospheric Administration (NOAA) are 

responsible for the development of the NWP models, the private sector focuses on using 

these models, in combination with data obtained from VERs, to develop power 

production forecasts tailored to the needs of individual clients (such as VERs, 

transmission providers and balancing authorities).114 

52. The Commission received a number of responses to questions in the Integrating 

VERs NOI addressing the manner in which public utility transmission providers and 

balancing authorities could be provided with the data necessary to support centralized 

VER power production forecasts. Bonneville indicates that the Commission could aid in 

the creation of more advanced VER power production forecasts through a requirement in 

the LGIA or SGIA that the VER disclose operational or meteorological data to the public 

 113 AWEA at 23, Iberdrola at 19, NERC at 7. 

114 ISO/RTO Council at 17. 
Docket No. RM10-11-000 - 43 - 

utility transmission provider for reliability and operational reasons. Another option 

mentioned by Bonneville and other parties is to modify the NERC Reliability Standards 

to require VERs to provide the data necessary to forecast VER power production.115 

53. NERC116 and others117 provided detailed lists of the types of operational and 

meteorological data that may be necessary to develop VER power production forecasting 

tools for both generators and public utility transmission providers. Additionally, the 

CAISO explains that it requires members of the PIRP to install meteorological equipment 

at their facilities to obtain wind speed, direction, barometric pressure, and ambient 

temperature. CAISO also requires real-time energy output and outage and de-rate 

information, among other data, from participating intermittent resources.118 CAISO 

explains that it is currently engaged in a stakeholder process to develop power production 

forecasting tools for solar resources with a special emphasis on the data necessary to 

forecast solar ramp events.119 SEIA, however, notes that solar power production 

forecasting is still in its infancy, and states that overly prescriptive reporting and 

 115 Bonneville at 40, G&T Cooperative at 12, NaturEner at 6. 

116 NERC at 5. 

117 CAISO at 22, Iberdrola at 17, ISO-NE at 13, Xcel at 6-7. 

118 CAISO at 13. 

119 Id. at 12. 
Docket No. RM10-11-000 - 44 - 

forecasting requirements for solar resources would be premature because the forecasting 

needs for solar facilities are only currently being identified.120

54. The Integrating VERs NOI also sought comments on whether public utilities 

should be required to maintain a meteorological reporting system and/or make 

meteorological data publically available to aid in the development of state-of-the-art 

forecasting tools. APS states that public utility transmission providers should not be 

required to post meteorological data on OASIS because the information typically comes 

from proprietary sources.121 Others, like AWEA, claim that it should be possible to share 

meteorological data publicly without compromising sensitive market data. AWEA 

warns, however, that protections should be in place to assure commercially sensitive data 

cannot be inferred from publicly available data.122 Bonneville notes that inclusion of data 

reporting requirements in the LGIA and SGIA would be appropriate because those 

agreements already include confidentiality measures.123 SEIA contends that the value of 

meteorological data does not come from its public disclosure, but rather, through the 

provision of such data to system operators and forecast service providers that incorporate 

the data into centralized and decentralized power production forecast. SEIA adds that 

 120 SEIA at 20. 

121 APS at 6. 

122 AWEA at 35. 

123 Bonneville at 40. 
Docket No. RM10-11-000 - 45 - 

operational data and information regarding generating unit outages should not be made 

publicly available.124 

2. Commission Discussion

55. In accord with the general consensus articulated by commenters, the Commission 

preliminarily finds that power production forecasting can play a significant role in 

removing barriers to the integration of VERs into the transmission system. The 

Commission believes 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. At the same 

time, the Commission recognizes that in areas of the country with very limited production 

from VERs, the implementation of power production forecasting for VERs could be of 

less use.125 

56. Therefore, the Commission does not propose, to require all public utility 

transmission providers to implement power production forecasting at this time. Instead, 

 124 SEIA at 20. 

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

available at http://www.nerc.com/files/IVGTF_Report_041609.pdf. (“[I]n many areas 

where wind power has not reached high penetration levels, uncertainty associated with 

the wind power has normally been less than that of demand uncertainty.... 

Consequently, power system operators have been able to accommodate current levels of 

wind plant integration and the associated uncertainty with little or no effort.”). 
Docket No. RM10-11-000 - 46 - 

the Commission proposes to require VER power production forecasting only by those 

public utility transmission providers seeking to require a subset of transmission 

customers to purchase, or otherwise account for, different volumes of generator 

regulation reserve service under proposed Schedule 10 (addressed below). This proposed 

reform is intentionally structured in a way that recognizes that VER power production 

forecasting may not be presently needed in all parts of the country (e.g., those with very 

limited production from VERs). Because there may be little need for power production 

forecasting on transmission systems where VERs are not present in significant numbers, 

the Commission proposes to refrain from imposing a one-size-fits-all requirement to use 

VER power production forecasting tools on all public utility transmission providers. 

57. The Commission is not proposing to require all public utility transmission 

providers to implement power production forecasting in this Proposed Rule. Nor is the 

Commission proposing a single appropriate method of cost recovery for the development 

and implementation of power production forecasts. Instead, the Commission seeks 

comments on how public utility transmission providers may recover the costs incurred to 

develop and deploy power production forecasting tools. 

58. The Commission’s proposal to adopt this requirement is founded on its review of 

the comments126 and other technical analysis127 indicating that the failure to consider 

 126 Bonneville at 5, Calpine at 13, M-S-R Public Power Agency at 4, NEPOOL at 

7. 

127 See supra P 45-46. 
Docket No. RM10-11-000 - 47 - 

VER power production forecasts in the hour-ahead, intra-day, day-ahead, and monthly 

time frames may result in an over-procurement of reserves, leading in turn to rates that 

may be unjust, unreasonable, and unduly discriminatory to VERs. Moreover, the 

Commission believes that the current ISO/RTO use of day-ahead, hour-ahead, and even 

intra-hour VER power production forecasts in unit commitment and reliability 

assessment analyses and dispatch procedures128 demonstrates the benefits to be gained 

from incorporating these tools into system operations. 

59. As indicated above, the Commission believes that power production forecasting 

on systems where VERs are present can lead to greater situational awareness as well as 

greater efficiency within the unit commitment, dispatch and reliability assessment 

processes. In the long-term, seasonal power production forecasts can identify months 

when the variability of VERs may need to be evaluated in light of planned outages for 

other generation. In the day-ahead and intra-day time frames, power production forecasts 

can be incorporated into reliability unit commitments, and in the hour ahead and shorter 

time frame, power production forecasts can be factored into dispatch instructions. Power 

production forecasts enable public utility transmission providers and balancing 

authorities to use their system resources in the most efficient manner. As mentioned by 

 128 ISO/RTO Council at 16. 
Docket No. RM10-11-000 - 48 - 

several parties,129 power production forecasts that predict the timing of potential ramp 

events are critical to situational awareness for a balancing authority. 

60. With respect to data necessary to develop and use a VER power production 

forecasting model, the Commission notes the NERC Reliability Standards130 may provide 

transmission providers with authority to request some operational data from generators. 

However, to facilitate the development and deployment of power production forecasting, 

the Commission proposes to revise the pro forma LGIA to require interconnection 

customers whose generating facilities are VERs to provide certain meteorological and 

operational data to the public utility transmission providers with whom they are 

interconnected. Such data are necessary to enable a public utility transmission provider 

to develop and deploy state-of-the-art power production forecasting tools. This proposal 

builds upon existing Commission data sharing requirements by outlining specific 

meteorological and operational data necessary to develop power production forecasts. 

The Commission also preliminarily finds that the pro forma LGIA includes adequate 

confidentiality protections for sensitive data obtained from the VERs.131 

 129 Iberdrola at 14-18, NERC at 3 & 7, and NREL at 3. 

130 TOP-001, R7.1 (generator outage); TOP-002-2, R14, 15 (changes in output 

capability and seven day production forecasts); TOP-003-1 R1-3 (outage information); 

TOP-006-2 (monitoring system conditions); and IRO-004, R4 (generation, operating 

reserve projections). 

131 See Pro Forma LGIA Article 22 (setting forth the confidentiality provisions 

applicable to data exchanged through the interconnection process). 
Docket No. RM10-11-000 - 49 - 

61. The Commission proposes revisions to the LGIA that will result in different types 

of meteorological information being provided by interconnection customers based on the 

type of VER they own and/or operate. In order to enable the most accurate power 

production forecasts, the proposed revision to the LGIA would require that such data be 

transmitted from the interconnection customer to the public utility transmission provider 

at or near real-time. The Commission proposes to revise the pro forma LGIA to require 

interconnection customers with 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 

proposes to revise the pro forma LGIA to require interconnection customers with solarbased 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 recognizes that different forecasts may require 

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

ground level. However, the Commission will refrain from proposing specific 

requirements in this respect, and instead proposes to allow the public utility transmission 

provider and interconnection customer to negotiate these details taking into account the 

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

in maintaining generation resource adequacy and transmission system reliability in its 

area. The resource-specific data requirements contained in individual LGIAs must be 

negotiated on a not unduly discriminatory basis. 
Docket No. RM10-11-000 - 50 - 

62. With respect to operational data, the Commission proposes 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. This 

proposal is similar to a recent CAISO proposal accepted by the Commission on 

April 30, 2010.132 As indicated in that case, the requirement to report outages down to a 

1 MW threshold will improve power production forecasting accuracy.133 Provision of 

VER outage data to this level of granularity will allow a public utility transmission 

provider to ascertain the extent to which VER current power production is a result of unit 

availability as opposed to changing weather conditions.134 If a VER is composed of a 

number of individual generating units, it is important for the public utility transmission 

provider to know how many individual generating units are capable of producing energy 

at any given time. Having such information will eliminate a significant source of 

forecasting error 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. For example, a 50 MW wind generating facility 

composed of fifty 1 MW turbines will have a maximum output of 50 MW when all of the 

 132 Cal. Indep. Sys. Operator Corp., 131 FERC ¶ 61,087 (2010). 

133 Id. P 42. 

134 Id. P 45. 
Docket No. RM10-11-000 - 51 - 

individual turbines are operating. However, if one of those turbines experiences a forced 

outage, then the maximum output of the facility is 49 MW. To the extent that a public 

utility transmission provider is not aware that one turbine is unable to produce energy, the 

power production forecast for that wind generating facility, during the time the turbine is 

out of service, will experience an additional uncertainty.135

63. The Commission seeks comment on the extent to which the lists of basic 

meteorological and operational data articulated above may be inadequate or incomplete 

to achieve the power production forecasting goals discussed herein. Further, the 

Commission seeks comments 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. 

64. In order to effectuate the above proposed changes, the Commission proposes to 

amend the pro forma LGIA to add a new definition of Variable Energy Resource to 

Article 1, add a new section Article 8.4, Provision of Data from a Variable Energy 

Resource and amend the table of contents. The Commission proposes to define 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 

 135 Id. P 19 (noting that while poor outage data make immediate forecasts less 

accurate, they also affect future forecasts because the past data serves as an input in the 

forecast algorithm for future time periods). 
Docket No. RM10-11-000 - 52 - 

facility owner or operator; and (3) has variability that is beyond the control of the facility 

owner or operator. The Commission believes this definition is consistent with NERC’s 

characterization of variable generation.136 The Commission seeks comment on this 

proposed definition. Consistent with our approach in Order Nos. 2003 and 661,137 the 

Commission proposes not to require retroactive changes to large generator 

interconnection agreements that are already in effect. However, the Commission seeks 

comment as to whether this approach would prevent public utility transmission providers 

from effectively implementing power production forecasting. 

65. Because the Commission proposes that this reform would apply only to 

interconnection customers whose generating facilities are VERs greater than 20 MW, we 

are proposing revisions only to the pro forma LGIA and not the pro forma Small 

Generator Interconnection Agreement (SGIA). By definition, the VER generating 

facility of an interconnection customer that would interconnect with a public utility 

transmission provider pursuant to an SGIA is less than or equal to 20 MW in size. The 

Commission seeks comment on whether this proposed reform should also apply to 

interconnection customers whose generating facilities are VERs of 20 MW or less and 

therefore require revisions to the pro forma SGIA. 

 136 See NERC, Accommodating High Levels of Variable Generation 13-14 (2009), 

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

137 Order No. 661, FERC Stats. & Regs. ¶ 31,186 at P 120; Order No. 2003, FERC 

Stats. & Regs. ¶ 31,146 at P 910. 
Docket No. RM10-11-000 - 53 - 

C. Generator Regulation Service-Capacity

66. In Order No. 888, the Commission identified six ancillary services necessary to 

provide basic transmission service and required public utility transmission providers to 

offer and/or provide them to transmission customers.138 Among the ancillary services 

that the Commission required public utility transmission providers to offer were 

Regulation and Frequency Response Service (Regulation Service) and Energy Imbalance 

Service.139 

67. 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).140 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 area141 to serve load in that 

 138 Order No. 888, FERC Stats. & Regs. at 31,703-04. 

139 Id.

140 Id. at 31,707-708 (referencing Promoting Wholesale Competition Through 

Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of 

Stranded Costs by Public Utilities and Transmitting Utilities, Notice of Proposed 

Rulemaking and Supplemental Notice of Proposed Rulemaking, FERC Stats. & Regs. 

¶ 32,514, at 33,086 (1995)). 

141 The term control area, used in the pro forma OATT, has been superseded in the 

NERC Reliability Standards and industry usage by the term balancing authority area. 
Docket No. RM10-11-000 - 54 - 

area.

142 However, the Commission did not require public utility transmission providers 

to offer Regulation Service for transmission service out of or through the transmissio

provider’s balancing authority area to serve load in another balancing authority area.

n 

 

143 

68. 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.144 In Order No. 888, the 

Commission required public utility transmission providers to offer Energy Imbalance 

Service for transmission service within and into the transmission provider’s balancing 

authority area to serve load in that area.145 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. 

69. As described above, 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) and energy (Energy Imbalance) costs of doing so from transmission 

customers serving load on their systems. At the time of Order No. 888, the Commission 

142 Id. at 31,717. 

143 Id.

144 Id. at 31,708. 

145 Id. at 31,717. 
Docket No. RM10-11-000 - 55 - 

believed that it was reasonable to only provide standardized ancillary service schedules 

for transmission used to service load because load (rather than generation) exhibited the 

greatest amount of variability.146 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. 

70. In Order No. 890, the Commission noted that the existing energy imbalance 

charges were the subject of significant concern and confusion in the industry.147 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.148 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 

 146 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. 

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). As mentioned above, wind capacity has developed at a 

significant pace, now totaling more than 35,000 MW of capacity. See supra note 17. 

147 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 634. 

148 Id.
Docket No. RM10-11-000 - 56 - 

generated.149 The Commission found that formalizing generator imbalance provisions in 

the pro forma OATT would standardize the 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.150 

71. 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.151 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.152 Accordingly, the Commission provided a 

mechanism by which public utility transmission providers could recover these costs, 

explaining that “[t]o the extent a transmission provider wishes to recover costs of 

 149 Id. P 663. 

150 Id. P 667. 

151 See 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.”). 

152 Id. P 690. 
Docket No. RM10-11-000 - 57 - 

additional regulation reserves associated with providing imbalance service,153 it must do 

so via a separate FPA section 205 filing demonstrating that these costs were incurred 

correcting or accommodating a particular entity’s imbalances.”154 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.155 Since the issuance of Order No. 890, 

on a case-by-case basis, the Commission has accepted proposals to recover such 

generator regulation charges pursuant to this mechanism.156

72. More recently, the Commission has addressed a number of filings for the 

provision of generator regulation service to wind energy resources. Public utility 

transmission providers have proposed different methods of allocating the costs of or 

assigning the responsibility for generator regulation service needed to manage the 

 153 Refers to costs associated with capacity used to provide generator imbalance 

reserve service that otherwise are not recovered through Schedule 3. 

154 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at n.401. 

155 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 313. 

156 See, e.g., Entergy Services Inc., 120 FERC ¶ 61,042, at P 62-66 (2007); Sierra 

Pac. Res. Operating Cos., 125 FERC ¶ 61,026 (2008). 
Docket No. RM10-11-000 - 58 - 

variability of VERs.157 These proposals have originated from public utility transmission 

providers that have a substantial amount of existing and projected wind resource 

generation on their systems, and the proposals have taken different approaches to 

managing and charging for the variability of wind resources. In NorthWestern, the 

transmission provider proposed to require wind energy resources using transmission 

service to export energy to another balancing authority area to provide for their own 

generator regulation service (either through becoming their own balancing authority 

areas, dynamically scheduling their energy out of NorthWestern’s balancing authority 

area, or by self-supplying the required generator regulation reserves).158 The 

Commission denied NorthWestern’s proposal, finding that a requirement for intermittent 

renewable generators to supply or otherwise account for their own generator regulation 

(i.e., capacity) service would undermine NorthWestern’s obligation to offer generator 

imbalance (i.e., energy) service under Schedule 9 of its OATT.159 

73. Unlike NorthWestern, in Westar, the transmission provider proposed to offer and 

charge for generator regulation service to all generation resources that use transmission 

 157 See, e.g., NorthWestern, 129 FERC ¶ 61,116, order on reh’g, 131 FERC 

¶ 61,202; Westar, 130 FERC ¶ 61,215; Puget Sound, 132 FERC ¶ 61,128; Bonneville 

Power Admin., June 29, 2009 Filing, Docket No. EF09-2011-000. 

158 NorthWestern, 129 FERC ¶ 61,116, order on reh’g, 131 FERC ¶ 61,202. 

159 NorthWestern, 129 FERC ¶ 61,116 at P 24. 
Docket No. RM10-11-000 - 59 - 

service to export energy from Westar’s balancing authority area.160 However, rather than 

proposing a standardized generator regulation service charge, Westar proposed to 

apportion the total charge between dispatchable generation resources and intermittent 

generation resources, commensurate with the respective generator regulation service 

burden each of these resources placed on Westar’s system.161 The Commission accepted 

Westar’s proposal as an interim measure to be in effect only until the implementation of 

an ancillary services market, and the balancing authority area consolidation in Southwest 

Power Pool, Inc. (SPP).162 

74. Most recently, in Puget Sound, the Commission evaluated a proposed “following 

service” for wind resources, which Puget described as a capacity service designed to 

follow and balance the within-hour variations in output from wind generators in Puget’s 

balancing authority area.163 Because Puget Sound’s proposed rate was based on the 

capacity cost of a proxy unit that it may never construct, the Commission found that 

Puget Sound had not shown its rate to be a reasonably accurate representation of the costs 

incurred in providing a following service to wind resources.164 

 160 Westar, 130 FERC ¶ 61,215 at P 1. 

161 Id. P 35-36. 

162 Id. P 35. 

163 Puget Sound, 132 FERC ¶ 61,128 at P 4. 

164 Id. P 35. 
Docket No. RM10-11-000 - 60 - 

75. In the Integrating VERs NOI, the Commission sought to explore whether the 

variability associated with the increased number of VERs may result in an over-reliance 

on procuring additional reserves.165 The Commission sought comment on the appropriate 

use of reserve products to ensure that reserves are being deployed efficiently such that the 

resulting rates are just, reasonable, and not unduly discriminatory.166 Particularly 

relevant to the proposed reform discussed below, the Commission also sought comment 

on whether the “pro forma OATT [should] be revised or new provisions added to 

expressly address the added reserve capacity necessitated by increased number of 

VERs.”167

1. Comments

76. The Commission received a number of comments on this issue, and different 

sectors of the industry hold widely divergent views on whether and in what manner 

public utility transmission providers should be allowed to charge VERs to account for the 

variability exhibited by those resources. The VER industry strongly opposes what it 

characterizes as “integration charges,” such as the above-described proposals from 

Westar and Puget Sound. AWEA views any proposal to assess a VER integration charge 

(i.e., any type of ancillary service) that is not justified by the variability of the actual 

 165 Integrating VERs NOI, 130 FERC ¶ 62,053 at P 35. 

166 Id.

167 Id. P 36. 
Docket No. RM10-11-000 - 61 - 

resources as discriminatory on its face.168 AWEA further contends that any added costs 

that result from VER integration are the result of the fact that current power system 

operating procedures were not designed to accommodate VERs.169 Accordingly, AWEA 

argues that before any integration charge is assessed to VERs, public utility transmission 

providers should first be required to implement operational reforms to update their 

systems, including the following: 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.170 

NextEra agrees, adding that procurement of ancillary services is based on numerous 

factors within a balancing authority area and that the costs of these services should not be 

allocated to individual facilities on an incremental basis.171 

77. NERC also contends that enhancements to existing operating criteria, practices, 

and procedures to account for large increases in the number of VERs should be 

developed through the stakeholder processes of reliability bodies, such as NERC, 

 168 AWEA at 15-16. 

169 Id. at 67. 

170 Id. See also Iberdrola at 37. 

171 NextEra at 25 (explaining that while contingency reserve requirements are set 

by the single largest contingency within a balancing authority area, the entity that owns 

that contingency is not charged an incremental rate for those reserves). 
Docket No. RM10-11-000 - 62 - 

Regional Entities and RTOs, noting that it is critical that practices such as reserve 

procurement for VERs are reviewed to assist system operators in managing increased 

uncertainty from VERs.172

78. Public utility transmission providers, however, generally hold a different view, 

seeking the flexibility to develop rate schedules that address the particular circumstances 

and resource mix present within their balancing authority areas. For example, Xcel 

recommends that the Commission encourage specific VER integration rates for public 

utility transmission providers outside of the regional markets. Xcel suggests that these 

integration rates could be based on increased regulation, load-following and cycling 

operations and maintenance impacts on the remainder of the balancing fleet providing the 

integration service, with VERs paying the costs of this service in place of conventional 

load-based billing.173 Westar states that “[t]he ancillary services provisions of the pro 

forma OATT should be revised or new provisions added to expressly address the added 

reserve capacity necessitated by increased number of VERs.”174 

79. Bonneville asserts that existing reserve products are not the most cost-effective 

means of supplying reserves of VERs and that balancing authorities should be permitted 

 172 NERC at 22-23. 

173 Xcel at 38. 

174 See Westar at 27-28. Westar contends that its OATT Schedule 3A approved by 

the Commission in Westar, 130 FERC ¶ 61,125 provides a model that can be followed. 
Docket No. RM10-11-000 - 63 - 

to establish new reserve services to address the uncertainty associated with VERs.175 

Bonneville cautions that if reliability or cost recovery issues arise in regions where VERs 

are concentrated, it will become increasingly difficult to build new projects in those 

regions.176 Bonneville also notes that the current generator imbalance service under 

Schedule 9 is for energy only and does not account for the capacity required to 

accommodate the full range of deviations within any scheduling period, hourly or intrahourly. To better account for this capacity, Bonneville states that it is necessary to charge 

for the regulation, following, and generator imbalance capacity components that are 

required to manage the variability of VERs.177

80. Bonneville also emphasizes the challenges faced by balancing authority areas in 

which a large number of VERs are located, and where much of the energy generated by 

these resources is exported to serve load in other balancing authority areas. Bonneville 

stresses that current policies are leading to duplicative and inefficient carrying of reserves 

by source and sink balancing authorities, as well as creating cost and reliability risks for 

balancing authority areas from which VERs are exported.178 Accordingly, Bonneville 

believes that rather than serving as default suppliers, source balancing authorities should 

 175 Bonneville at 84. 

176 Id. at 2. 

177 Id. at 94. 

178 Id. at 3. 
Docket No. RM10-11-000 - 64 - 

strive to facilitate options (e.g., self-supply and dynamic transfers) for VER exporters to 

acquire balancing services from alternative sources.179 Bonneville argues that clear 

delineation between being a default supplier versus a fully compensated party to a 

defined transaction is essential to the sustainable growth of VERs.180 

81. Some commenters urge the Commission to eliminate any obligation on the part of 

a public utility transmission provider to ensure that sufficient capacity is available to 

manage the moment-to-moment variability of VERs located within their balancing 

authority area, and instead place that obligation on the VER and/or the entity using the 

VER to serve load.181 NorthWestern contends that “because not all transmission 

providers will have the resources available to provide the service, there should be no 

obligation on the transmission provider to do so.”182 Instead, NorthWestern argues that a 

new ancillary services schedule could define the amount of service necessary to maintain 

system reliability and the options the transmission customer has to acquire and/or self-

 179 Id. at 22. 

180 Id. at 4. 

181 Bonneville at 22 (arguing that the VER owner and the entity that is using the 

VER for its own load service should have the fundamental planning, operational, and 

financial responsibility for ensuring that there is sufficient capacity available to manage 

the full range of variability of the VER—including regulation, load following, generator 

imbalance, and extreme tail events (large up and down ramp events)). 

182 See NorthWestern at 30. 
Docket No. RM10-11-000 - 65 - 

supply the service.183 Some commenters urge the Commission to require VERs to submit 

“balancing plans” to host balancing authorities during the interconnection process, 

including such things as third-party balancing arrangements, comparisons of a VER’s 

balancing needs with products offered by the host balancing authority, and requests to the 

host balancing authority to develop new balancing products and/or dynamically 

scheduling tools.184 

82. Several entities suggest that it is premature for the Commission to require new or 

different reserve products. For example, EEI argues that the Commission should first 

allow industry-based studies addressing the reliability-related reserve issues to proceed. 

EEI believes that after the reliability issues are addressed, the Commission should 

examine the ancillary services mandated in the pro forma OATT to determine whether 

they provide the proper market-based incentives for supply and demand resources to 

mitigate the costs of variability associated with VERs.185 EEI stresses, however, that the 

Commission should not mandate a particular outcome, such as a required reserve product, 

and instead should allow regional solutions to be developed.186

 183 Id.

184 PUD No. 2 Grant County at 4, Bonneville at 25-26. 

185 EEI at 20-21. 

186 Id. at 21-22. 
Docket No. RM10-11-000 - 66 - 

83. Other entities, such as NREL and NaturEner, indicate that different reserve 

products should be used to respond to different types of events. NREL indicates that 

where VER ramp events frequently exceed the ramp capabilities of existing resources, a 

ramp service may be justified; however, where such VER ramp events happen 

infrequently (what NREL refers to as “tail” events) a service more like supplemental or 

non-spinning reserves may be desirable.187 NaturEner argues that it is not financially 

feasible to use regulation reserves for rare VER ramp events, and that public utility 

transmission providers should be able to use contingency reserves188 for such events.189 

Lastly, the Commission notes that commenters express various opinions, as well as 

confusion, regarding a public utility transmission provider’s ability to use contingency 

reserves to manage extreme VER ramp events.190 

2. Commission Discussion

84. As the Commission explained in NorthWestern, 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 

 187 NREL at 15. 

188 Contingency reserves are reserves held and deployed in the event of an 

unexpected failure or outage of a generation, non-generation or transmission resource. 

189 NaturEner at 21. 

190 Westar at 27, Puget at 13, Exelon 15-16, Xcel at 36-37, Grant PUD at 25-26. 
Docket No. RM10-11-000 - 67 - 

imbalance service.191 The Commission also stated in NorthWestern that eliminating this 

obligation or placing conditions on the ability of transmission customers using VERs to 

receive this capacity service would undermine the public utility transmission provider’s 

ability to offer generator imbalance service.192 In this way, the Commission in 

NorthWestern recognized public utility transmission providers’ obligation to provide this 

generator regulation service to customers using transmission service to deliver energy 

from generators located within their balancing authority area. 

85. In the Proposed Rule, the Commission seeks to bring consistency to the manner in 

which public utility transmission providers carry out this obligation by incorporating 

Schedule 10—Generator Regulation and Frequency Response Service into the pro forma

OATT. In doing so, the Commission seeks to bring clarity and transparency to the rates, 

terms and conditions that apply to the provision of this service, as well as the mechanism 

through which public utility transmission providers can recover the associated costs. At 

the same time, we recognize that on many transmission systems, especially those that do 

not have a significant number of transmission customers that export energy, public utility 

transmission providers already recover the costs of providing regulation service to 

transmission customers serving load on their systems through Schedule 3 of the pro 

forma OATT. The proposed reform would require public utility transmission providers 

 191 NorthWestern, 129 FERC ¶ 61,116 at P 27. 

192 See id. P 24. 
Docket No. RM10-11-000 - 68 - 

to file Schedule 10, setting forth the transmission provider’s obligation to offer generator 

regulation service and the rate at which the service would be provided. However, the 

proposed reform refrains from requiring a volumetric reserve requirement until the public 

utility transmission provider chooses to make a subsequent filing proposing an 

appropriate volumetric reserve requirement. 

86. We recognize that the Commission adopted, in Order No. 890, a case-by-case 

approach to filings by public utility transmission providers seeking to recover the costs of 

additional regulation reserves associated with providing generator imbalance service.193 

However, in light of the increasing number and diversity of proposals filed with the 

Commission, it is appropriate to revisit the case-by-case approach and bring a measure of 

consistency to the manner in which generation regulator reserve service is provided. 

87. Therefore, the Commission proposes 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. 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-to-moment variations attributable to 

generation. The proposed reform recognizes this de facto obligation and establishes a 

generic rate schedule (Schedule 10—Generator Regulation and Frequency Response 

Service) through which public utility transmission providers may recover the costs of 

 193 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 689 n.401, order on reh’g, 

Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 313. 
Docket No. RM10-11-000 - 69 - 

providing this service. The Commission preliminarily finds that clarifying the manner by 

which public utility transmission providers may recover the costs associated with 

fulfilling their obligation to offer this service will remove barriers to the integration of 

VERs by eliminating public utility transmission providers’ uncertainty regarding cost 

recovery. 

88. Proposed 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 will 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 transmission provider’s balancing authority area 

and when they are exporting to load in other balancing authority areas. 

89. Under proposed 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 transmission provider’s 

balancing authority area. A transmission customer subject to Schedule 10 must either 

take service pursuant to this proposed rate schedule or demonstrate that it has satisfied its 

regulation service obligation through dynamically scheduling its generation to another 
Docket No. RM10-11-000 - 70 - 

balancing authority area194 or by self-supplying regulation reserve capacity from 

generation or non-generation resources.195 Furthermore, consistent with Order No. 890, 

public utility transmission providers may not charge transmission customers for 

regulation reserves under both Schedule 3 and proposed Schedule 10 for the same 

transaction.196 

90. As with generator imbalance service, it may be appropriate for a public utility 

transmission provider to allow a generator located within its balancing authority area, 

which is not otherwise a transmission customer, to execute a service agreement for 

generator regulation service. 197 In the instance where multiple transmission customers 

 194 See Joint Initiative at 7 (describing the development of the Dynamic 

Scheduling System in order to simplify, enhance and reduce the cost of dynamically 

scheduling resources between Balancing Authority Areas across the western 

interconnection). 

195 See Order No. 888, FERC Stats. & Regs. at 31,717 (establishing the same 

options to dynamically schedule or self-supply for customers subject to Schedule 3 of the 

pro forma OATT). The self-supply option would allow VERs to acquire regulating 

reserves to meet their schedules or to self-curtail according to specified criteria in order to 

reduce the amount of reserves they are obligated to supply or purchase. See also Order 

No. 890, FERC Stats. & Regs. ¶ 31,241 at P 888 (modifying Schedules 2, 3, 4, 5, 6, and 9 

of the pro forma OATT to indicate that the services provided under those rate schedules 

may be provided by generating units as well as other non-generation resources such as 

demand response). 

196 See 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). See also 

Entergy, 120 FERC ¶ 61,042 at P 62-66; Sierra Pac. Res. Operating Cos., 125 FERC 

¶ 61,026; Westar, 130 FERC ¶ 61,215 at P 4. 

197 See Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 288. 
Docket No. RM10-11-000 - 71 - 

are delivering energy from a single generator, the public utility transmission provider 

would need to apportion among those multiple transmission customers the generator 

regulation service charge for such generator. The apportionment process could be 

difficult and administratively burdensome for the public utility transmission provider. 

Accordingly, by establishing a contractual arrangement between the public utility 

transmission provider and such generator through the execution of a service agreement, 

the public utility transmission provider can charge the generator directly for generator 

regulation service, and any transmission customer delivering energy from such generator 

will be deemed to have satisfied its obligation to purchase generator regulation service 

under section 3 and Schedule 10. 

91. The Commission proposes that this service should apply to transmission customers 

delivering energy from all generators (as opposed to VERs only) located within a public 

utility transmission provider’s balancing authority area. The Commission reiterates that 

in establishing proposed Schedule 10, we are not changing the nature of the services that 

a public utility transmission provider must offer its transmission customers. Nothing in 

this 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 proposal here is simply 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. 
Docket No. RM10-11-000 - 72 - 

92. As with Schedule 3, the proposed Schedule 10 charge will be the product of two 

components: a per-unit rate for regulation reserve capacity and a volumetric component 

for regulation reserve capacity. The regulation reserve capacity requirement is the cost 

and volume of unloaded generation or other non-generation resources held in reserve to 

manage the variability of load (under Schedule 3) and generation (under proposed 

Schedule 10) in a reliable manner. 

93. Schedule 3 and the proposed Schedule 10 both are 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 proposes 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 

proposed Schedule 10. 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. Moreover, the Commission notes 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 proposed generator regulation rate that the Commission 

accepted in Westar. 

94. Whereas the Commission finds that the per-unit rate for service under proposed 

Schedule 10 should be the same as the rate for service under existing Schedule 3, the 

Commission recognizes that generators and load may exhibit different amounts of overall 
Docket No. RM10-11-000 - 73 - 

variability. Moreover, the Commission recognizes that variability may be different 

among different types of resources. A number of commenters indicate that VERs may 

impose a disproportionate impact on overall system variability, thereby requiring public 

utility transmission providers to hold a greater per MW amount of regulation reserves for 

VERs than for load and/or other generation resources.198 As a general matter, the 

Commission agrees that regulation reserve costs should be allocated to transmission 

customers consistent with cost causation principles. Further, the Commission does not 

propose to mandate a particular method for apportioning the volume of regulation 

reserves of proposed Schedule 10. Instead, we preliminarily find that each public utility 

transmission provider should propose a method of apportioning such volumes of 

regulation reserves, based on the facts and circumstances of its individual system. For 

example, the Commission recognizes 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. This may be the case to the extent 

that the impact of VERs on its 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. 

95. Alternatively, where a subset of transmission customers causes a public utility 

transmission provider to procure a different per unit volume of regulation reserves than 

 198 Westar at 7, NorthWestern 5-6. 
Docket No. RM10-11-000 - 74 - 

for other transmission customers, public utility transmission providers may require that 

subset of transmission customers to purchase, or otherwise account for, a different 

volume of generator regulation reserves, commensurate with its relative impacts on the 

system. The Commission accepted such a proposal (on an interim basis) in Westar, 

where a public utility transmission provider demonstrated the disproportionate impact of 

VERs on overall system variability, and the Commission found that it was consistent with 

cost causation principles for the public utility transmission provider to allocate a different 

regulation reserve capacity requirement to those resources.199 Accordingly, under 

proposed Schedule 10, a public utility transmission provider may require a transmission 

customer delivering energy from VERs to purchase, or otherwise account for, a different 

volume of generator regulation reserve to the extent that the different regulation reserve 

volumes are supported by data showing that, on the public utility transmission provider’s 

system, VERs impose a different per unit impact on overall system variability than 

conventional generating units. 

96. At the same time, the Commission acknowledges commenters who argue that 

public utility transmission providers should be required to adopt operational reforms to 

mitigate the volume of regulation reserves that may be required to manage the variability 

of VERs. As discussed above, AWEA contends that before imposing any specific 

 199 Westar, 130 FERC ¶ 61,215 at P 35-36. In Westar, the proposal was an interim 

measure that would be in place only until the implementation of Southwest Power Pool’s 

balancing area consolidation and ancillary services market. Id.
Docket No. RM10-11-000 - 75 - 

generator regulation reserve costs to VERs, public utility transmission providers should 

first implement the following: 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.200 

We agree that public utility transmission providers should implement certain operational 

reforms before requiring transmission customers delivering energy from VERs to 

purchase, or otherwise account for, different volumes of generator regulation service than 

those transmission customers delivering energy from other generators. 

97. Accordingly, a public utility transmission provider may not require different 

volumes of generator regulation service from transmission customers delivering energy 

from VERs as opposed to conventional generators without implementing intra-hourly 

scheduling and power production forecasting as discussed in this Proposed Rule. 

Subsequently, a public utility transmission provider may require the subset of 

transmission customers who deliver energy from VERs to purchase, or otherwise account 

for, different volumes of generator regulation service, provided that it demonstrates that 

the different regulation reserve volume is necessitated by that subset of transmission 

customers. 

 200 AWEA at 67. See also Iberdrola at 37. 
Docket No. RM10-11-000 - 76 - 

98. However, the Commission will not require public utility transmission providers to 

implement the other reforms suggested by AWEA at this time. While the Commission 

believes that it is appropriate to require public utility transmission providers to implement 

those reforms that are within their individual control (as is the case with intra-hourly 

scheduling and power production forecasting) some of AWEA’s proposals would require 

measures that go beyond an individual public utility transmission providers’ reasonable 

control (such as the development of ancillary services markets or a regional ACE 

diversity interchange) and are coordinated reforms that require the cooperation of other 

transmission providers. As discussed above, industry stakeholder groups are currently 

addressing a number of these issues, and our intention here is to propose those reforms 

that can be adopted in the near-term by individual public utility transmission providers. 

99. In addition to the generator regulation reform proposed herein, commenters in 

response to the Integrating VERs NOI address a number of issues related to ancillary 

services reforms that do not appear ripe for Commission action in this proceeding. For 

example, commenters suggest the possibility of reforming rules associated with the 

provision of contingency reserves to allow the use of these reserves to cover infrequent 

but significant VER ramp events, described as “tail” events.201 Still other commenters 

suggest that the Commission revisit the rules applicable to VERs regarding their 

 201 See, e.g., NREL at 16-17. 
Docket No. RM10-11-000 - 77 - 

obligations to provide reactive power capabilities.202 The Commission proposes to make 

no additional reforms to the ancillary services sections of the OATT beyond those 

proposed at this time. We believe these suggested reforms require further study and will 

benefit from continued stakeholder discussions, such as through NERC’s Integration of 

Variable Generation Task Force. Accordingly, the Commission will continue to monitor 

these and other potential ancillary services reforms, but will not address them in this 

proceeding. 

100. Finally, the Commission seeks comments from NERC and industry stakeholders 

on the steps needed to resolve the confusion regarding the use of contingency reserves to 

manage extreme ramp events of VERs.203 The Commission seeks 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. 

 202 See, e.g., Bonneville at 100, Xcel at 41, Nevada Power at 7-8. 

203 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.” 
Docket No. RM10-11-000 - 78 - 

VI. Compliance Filings 

101. The Commission proposes that each public utility transmission provider must 

comply with the requirements of this Proposed Rule. The Commission proposes to 

require each public utility transmission provider to submit a compliance filing within six 

months of the effective date of the final rule in this proceeding revising its OATT, LGIA, 

or other document(s) subject to the Commission’s jurisdiction as necessary to 

demonstrate that it meets the proposed requirements set forth in this Proposed Rule.204 

Accordingly, in the compliance filing required by the Proposed Rule, 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. 

102. In some cases, 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. Where these provisions are being modified 

by the final rule, public utility transmission providers must either comply with the final 

 204 See Appendix B and C for the proposed pro forma OATT and LGIA provisions 

consistent with this Proposed Rule. 
Docket No. RM10-11-000 - 79 - 

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. 

103. The Commission will assess whether each compliance filing satisfies the proposed 

requirements and principles stated above and issue additional orders as necessary to 

ensure that each public utility transmission provider meets the requirements of this 

Proposed Rule. 

104. The Commission proposes that transmission providers that are not public utilities 

will have to adopt the requirements of this Proposed Rule as a condition of maintaining 

the status of their safe harbor tariff or otherwise satisfying the reciprocity requirement of 

Order No. 888.205

105. Subsequent to the acceptance of its compliance filing, a public utility transmission 

provider will have the opportunity to justify, in a section 205 filing, a proposal (1) to 

require all transmission customers who are delivering energy 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.206 Where a public utility transmission provider proposes the same volume of 

 

 

(continued...) 

205 Order No. 888, FERC Stats. & Regs. at 31,760-763. 

206 The Commission expects that in any subsequent filing to establish a volumetric 

requirement in Schedule 10, public utility transmission providers will address how 
Docket No. RM10-11-000 - 80 - 

generator regulation reserves for all generators, it must demonstrate that the volume of 

regulation reserves required of transmission customers delivering energy from generators 

located within its balancing authority area is commensurate with their proportionate 

effect on net system variability and taking account of diversity benefits.207 Such a filing 

must 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. 

106. 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, it must 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. Such a filing must show that the public utility transmission 

 

Schedule 10 and Schedule 3 will work together to allow for the recovery of total 

regulation reserve costs. 

207 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. 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 the Commission finds that sharing 

of these benefits among the customers is reasonable. Westar, 130 FERC ¶ 61,215 at P 

37-38. 
Docket No. RM10-11-000 - 81 - 

provider has fully implemented (or been granted waiver from) the intra-hourly scheduling 

requirement set forth in the Proposed Rule and must also show the public utility 

transmission provider has developed and deployed power production forecasting for 

VERs. The Commission seeks comment on the manner by which a public utility 

transmission provider should be required to show they have developed and deployed 

power production forecasts. 

107. The Commission proposes that any such subsequent filing including different 

volumetric requirements for different subsets of transmission customers should be 

supported with actual data collected over a one year period subsequent to the 

implementation of intra-hourly scheduling and power production forecasting for VERs. 

The Commission acknowledges that this proposal may delay a public utility’s ability to 

recover the cost associated with providing generator regulation service. We further 

acknowledge that there may be alternative methods for developing the data necessary to 

support different volumetric requirements for different subsets of transmission customers. 

The Commission seeks comment as to such methods of demonstration, how they could 

support a Commission finding that the Schedule 10 filing is just and reasonable, and 

ways in which these methods of demonstration may be preferable to this aspect of the 

Commission’s proposal. 
Docket No. RM10-11-000 - 82 - 

VII. Information Collection Statement

108. The following collections of information contained in this Proposed Rule are 

subject to review by the Office of Management and Budget (OMB) under section 3507(d) 

of the Paperwork Reduction Act of 1995.208 OMB’s regulations require approval of 

certain information collection requirements imposed by agency rules.209 The 

Commission solicits comments on the Commission’s need for this information, whether 

the information will have practical utility, the accuracy of the burden estimates, ways to 

enhance the quality, utility, and clarity of the information to be collected or retained, and 

any suggested methods for minimizing respondents’ burden, including the use of 

automated information techniques. 

109. Additionally, the Commission encourages comments regarding the time burden 

expected to be required to comply with the proposed rule regarding intra-hourly 

transmission scheduling requirements and the requirement to coordinate and provide 

meteorological and operational data where relevant. Specifically, the Commission seeks 

comment on: (1) the additional burden and cost (human, hardware and software) 

associated with implementation, operation and maintenance of intra-hour transmission 

scheduling in 15 minute increments; and (2) the additional time burden and cost (human, 

hardware and software) involved in implementation, operation and maintenance for an 

 208 44 U.S.C. 3507(d) (2006). 

209 5 C.F.R. 1320.11 (2010). 
Docket No. RM10-11-000 - 83 - 

interconnection customer to coordinate and provide meteorological and operational data 

to the public utility transmission provider where relevant. 

Burden Estimate: The additional estimated public reporting burdens for the proposed 

reporting requirements in this rule are as follows. 

Data Collection 

FERC 516 

Number of 

Respondents 

[1] 

Number of 

Responses 

[2] 

Hours per 

Response 

[3] 

Total Annual 

Hours 

[1 X 2 X 3] 

Conforming tariff 

changes to require 

intra-hourly 

scheduling or 

deviation request 

(18 CFR 

35.28(c)(1)(vi)) 

134 1 3 402 

Implementation of 

intra-hourly 

scheduling (15 

minute intervals) 

134 1 6 initial set up,

2 maintenance 

and operation 

804 initial year, 

268 subsequent 

years 

Addition of 

ancillary service 

rate schedule, 

Schedule 10 or 

deviation request 

(18 CFR 

35.28(c)(1)(vi)) 

134 1 5 670 

Conforming 

changes to LGIA 

(for 

meteorological 

and operational 

data provided by 

Interconnection 

Customers with 

VERs) or 

deviation request 

(18 CFR 

35.28(f)(1)(v)) 

134 1 7 938 
Docket No. RM10-11-000 - 84 - 

Provision of 

meteorological 

and operational 

data by 

Interconnection 

Customers with 

VERs to public 

utility 

transmission 

providers 

270* 1 4 initial set up,

2 maintenance 

and operation 

1,080 initial 

year, 540 

subsequent 

years 

Totals 3,894 initial 

year, 2,818 

subsequent 

years 

*The Commission estimates that there are approximately 270 VERs under construction, 

permitted, with an application pending, or proposed to come online 2010-2011 

potentially subject to this requirement. 

Cost to Comply: The Commission has projected the cost of compliance to be $443,916 

in the initial year and $321,252 in subsequent years. 

Total Annual Hours for Collection in initial year (3,894 hours) @ $114 an hour [average 

cost of attorney ($200 per hour), consultant ($150), technical ($80), and administrative 

support ($25)] = $443,916 

Total Annual Hours for Collection in subsequent years (2,818 hours) @ $114 an hour = 

$321,252. 

Title: FERC-516, Electric Rate Schedules and Tariff Filings 

Action: Proposed Collection. 

OMB Control No. 1902-0096 

Respondents for this Rulemaking: Businesses or other for profit and/or not-for-profit 
Docket No. RM10-11-000 - 85 - 

institutions. 

Frequency of Information: As indicated in the table. 

Necessity of Information: The Federal Energy Regulatory Commission is proposing 

changes to the pro forma OATT in order to remedy operational challenges related to the 

increased integration of VERs to the bulk electric system. The purpose of this Proposed 

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 Proposed Rule seeks to achieve this goal by 

amending the pro forma OATT and LGIA to incorporate provisions that require intrahourly transmission scheduling, 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 and create a 

generic ancillary service schedule. 

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 

internal review, that there is specific, objective support for the burden estimates 

associated with the information collection requirements. 

110. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE, 
Docket No. RM10-11-000 - 86 - 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], 

e-mail: DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 

111. Comments on the collections of information and the associated burden estimates 

in the proposed rule should be sent to the Commission in this docket and 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], at the following e-mail address: 

oira_submission@omb.eop.gov. Please reference OMB Control No. 1902-0096 and the 

docket number of this proposed rulemaking in your submission. 

VIII. Environmental Analysis

112. 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.210 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact Statement is required for this Proposed Rule 

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 

 210 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 - 87 - 

energy subject to the Commission’s jurisdiction, plus the classification, practices, 

contracts and regulations that affect rates, charges, classifications, and services.211

IX. Regulatory Flexibility Act Analysis 

113. The Regulatory Flexibility Act of 1980 (RFA)212 generally requires a description 

and analysis of final rules that will have a significant economic impact on a substantial 

number of small entities. This Proposed Rule applies to public utilities that own, control 

or operate interstate transmission facilities other than those that have received waiver of 

the obligation to comply with Order Nos. 888, 889, and 890. The total estimated number 

of public utility transmission providers that, absent waiver, would have to modify their 

current OATTs by filing the revised pro forma OATT is 134. Of these public utility 

transmission providers, an estimated 10 filers, or 7.5 percent, have output of four million 

MWh or less per year.213 The Commission does not consider this a substantial number 

and, in any event, each of these entities may seek waiver of these requirements. The 

criteria for waiver that would be applied under this rulemaking for small entities is 

 211 18 C.F.R. 380.4(a)(15) (2010). 

212 5 U.S.C. 601-612 (2006). 

213 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. Based on the filers of the annual FERC Form 1 and Form 1-F, as well 

as the number of companies that have obtained waivers, we estimate that 7.5 percent of 

the filers are “small.” 
Docket No. RM10-11-000 - 88 - 

unchanged from that used to evaluate requests for waiver under Order Nos. 888, 889, and 

890. 

114. As the Commission has previously explained, in determining whether a regulatory 

flexibility analysis is required, the Commission is required to examine only direct 

compliance costs that a rulemaking imposes on small business.214 It is not required to 

examine indirect economic consequences, nor is it required to consider costs that an 

entity incurs voluntarily. As discussed above, only public utility transmission providers 

are required to make filings in compliance the Proposed Rule. However, to the extent 

that interconnection customers whose generating facilities are VERs are also impacted by 

the Proposed Rule, such impacts only apply to those interconnection customers subject to 

standard generator interconnection agreements for VERs larger than 20 MW,215 which 

exceeds the threshold of the small business size standard of the Small Business 

Administration. Accordingly, the Commission certifies that the proposed rule will not 

have a significant economic impact on a substantial number of small entities. 

 214 Credit Reforms in Organized Wholesale Electric Markets, 133 FERC ¶ 61,060, 

at P 184 (2010). 

215 Standard generator interconnection agreements and procedures are segmented 

into large generators which are greater than 20 MW and small generators which are 20 

MW or less. This proposed rule applies only to generators in the LGIA category of more 

than 20 MWs. 
Docket No. RM10-11-000 - 89 - 

X. Comment Procedures

115. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due [Insert_Date that is 

60 days from publication in the FEDERAL REGISTER]. Comments must refer to 

Docket No. RM10-11-000, and must include the commenter's name, the organization 

they represent, if applicable, and their address in their comments. 

116. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing. 

117. Commenters that are not able to file comments electronically must send an 

original copy of their comments to: Federal Energy Regulatory Commission, Secretary 

of the Commission, 888 First Street NE, Washington, DC 20426. 

118. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters. 
Docket No. RM10-11-000 - 90 - 

XI. Document Availability

119. 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 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426. 

120. 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. 

121. 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. 

List of subjects in 18 C.F.R. Part 35 

Electric power rates; Electric utilities; Reporting and record-keeping requirements 

By direction of the Commission. 

Kimberly D. Bose, 

Secretary.
Docket No. RM10-11-000 - 91 - 

In consideration of the foregoing, the Commission proposes to amend Part 35, 

Chapter I, Title 18, Code of Federal Regulations, as follows: 

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 - 92 - 

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 - 93 - 

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 - 94 - 

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 - 95 - 

(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. 

* * * * * 

(e) Non-public utility procedures for tariff reciprocity compliance. 
Docket No. RM10-11-000 - 96 - 

(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 

interconnection procedures and agreement and the standard small generator 

interconnection procedures and agreement. 
Docket No. RM10-11-000 - 97 - 

(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 - 98 - 

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 Inquiry on Integration of Variable Energy Resources—

Docket No. RM10-11-000, January 2010 

Short Name or Acronym Commenter

A123 A123 Systems, Inc. 

AEP American Electric Power Service 

Corporation 

Altresco Altresco Integrated LLC 

American Gas American Gas Association 

APPA American Public Power Association 

Argonne National Lab Argonne National Laboratory 

APS Arizona Public Service Company 

Avista Avista Corporation 

AWEA American Wind Energy Association 

Beacon Power Beacon Power Corporation 

Ben Carver Ben Carver 

Bernard Lee Bernard S. Lee 

Bonneville Bonneville Power Administration 

BP Energy BP Energy Company 

BrightSource BrightSource Energy, Inc. 

Brookfield Brookfield Renewable Power Inc. 

California ISO California Independent System Operator 

Corporation 
Docket No. RM10-11-000 - 99 - 

CMUA 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 

California PUC California Public Utilities Commission 

California State Water Project California Department of Water Resources 

State Water Project 

CalWEA California Wind Energy Association 

Calpine Calpine Corporation 

Cazalet Group Edward G. Cazalet 

Chelan County PUD Public Utility District No. 1of Chelan County, 

Washington 

Clean Line Clean Line Energy Partners, LLC 

Clean Urban Energy Clean Urban Energy, Inc. 

CAREBS Coalition to Advance Renewable Energy 

through Bulk Storage 

ColumbiaGrid ColumbiaGrid 

Constellation Constellation Energy Commodities Group, Inc. 
Docket No. RM10-11-000 - 100 - 

and Constellation New Energy, Inc. 

Covanta Covanta Energy Corporation 

Detroit Edison Detroit Edison Corporation 

Dominion Dominion Resources Services, Inc. 

Duke Duke Energy Corporation 

EEI Edison Electric Institute 

ELCON Electricity Consumers Resource Council 

Entergy Entergy Services, Inc. 

E.ON E.ON U.S. LLC 

E.ON Climate & Renewables E.ON Climate & Renewables North 

North America America 

EPSA Electric Power Supply Association 

Exelon Exelon Corporation 

Federal Trade Commission Federal Trade Commission 

FirstEnergy FirstEnergy Affiliates 

FIT Coalition FIT Coalition 

G&T Cooperative Associated Electric Cooperative, Inc.; Basin 

Electric Power Cooperative; Tri-State Gas & 

Transmission Association, Inc. 

Glenn Schleede Glenn R. Schleede 

Grant PUD Public Utility District No. 2 of Grant County, 

Washington 

HDR Engineering HDR Engineering, Inc of the Carolinas 

Iberdrola Iberdrola Renewables, Inc. 
Docket No. RM10-11-000 - 101 - 

Idaho Power Idaho Power Company 

Imperial Irrigation District Imperial Irrigation District (CA) 

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 & 

Intermountain Power Producers Coalition. 

Indicated New York Transmission Central Hudson Gas & Electric Corporation; 

Owners Consolidated Edison Company of New York, 

Inc.; Long Island Power authority; New York 

Power Authority; New York State Electric & 

Gas Corporation; Orange and Rockland Utility, 

Inc.; and Rochester Gas and Electric 

Corporation 

Invenergy Wind Invenergy Wind Development LLC 

ISO New England ISO New England Inc. 

ISO/RTO Council California Independent System Operator; 

Electric Reliability Council of Texas; ISO New 

England, Inc.; Midwest Independent 

Transmission System Operator, Inc.; New York 

Independent System Operator; 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 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); 

IID Energy; JEA (Jacksonville, FL); Long 

Island Power Authority; Lower Colorado River 
Docket No. RM10-11-000 - 102 - 

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 

LAWP Department of Water and Power of the City of 

Los Angeles 

Manitoba Hydro Manitoba Hydro 

Mark Strauch Mark Strauch 

MidAmerican MidAmerican Energy Holdings Company 

Midwest ISO Midwest Independent Transmission System 

Operator, Inc. 

Midwest ISO Transmission Owners Ameren Services Company (as agent for Union 

Electric Company; Central Illinois Public 

Service Company; Central Illinois Light Co., 

and Illinois Power Company); City of Columbia 

Water and Light Department (Columbia, MO); 

City Water, Light & Power (Springfield, IL); 

Great River Energy; Hoosier Energy Rural 

Electric Cooperative, Inc.; Indiana Municipal 

Power Agency; Indianapolis Power & Light 

Company; (Minnesota Power (and its subsidiary 

Superior Water, L&P); Montana-Dakota 

Utilities Co.; Northern Indiana Public Service 

Company; Northern States Power Company 

(Minnesota and Wisconsin corporations); 

Northwestern Wisconsin Electric Company; 

Otter Tail Power Company; Southern Illinois 

Power Cooperative; Southern Indiana Gas & 

Electric Company; Southern Minnesota 

Municipal Power Agency; Wabash Valley 

Power Association, Inc.; and Wolverine Power 

Supply Cooperative, Inc. 
Docket No. RM10-11-000 - 103 - 

Modesto Irrigation District Modesto Irrigation District 

Morgan Stanley Morgan Stanley Capital Group Inc. 

M-S-R Public Power Agency Modesto Irrigation District; City of Santa Clara, 

California; and City of Redding, California 

NARUC National Association of Regulatory Utility 

Commissioners

NEMA National Electrical Manufacturers Association 

and NEMA Energy Storage Council 

National Grid National Grid USA 

National Hydropower National Hydropower Association 

NRECA National Rural Electric Cooperative Association 

Natural Gas Natural Gas Supply Association 

NaturEner NaturEner USA, LLC 

Nebraska Power Nebraska Power Association 

NEPOOL Participants New England Power Pool Participants 

Committee 

NV Energy Nevada Power Company and Sierra Pacific 

Power Company 

New England States’ Committee on New England States’ Committee on 

Electricity Electricity 

New York ISO New York Independent System Operator, Inc. 

New York PSC New York State Public Service Commission 

NextEra NextEra Energy Resources, LLC 

NERC North American Electric Reliability 

Corporation 
Docket No. RM10-11-000 - 104 - 

NOAA National Oceanic and Atmospheric 

Administration 

NorthWestern NorthWestern Corporation 

Northeast Utilities Northeast Utilities Service Company 

NREL National Renewable Energy Research 

Laboratory’s Transmission and Grid Integration 

Group 

NRG NRG Energy, Inc. 

Opatrny Consulting Opatrny Consulting, Inc. 

Organization of SE Utilities Georgia Transmission Corporation; 

Jacksonville Electric Authority; Municipal 

Electric Authority of Georgia; Orlando Utilities 

Commission; Progress Energy, Inc.; South 

Carolina Electric & Gas Corporation; South 

Carolina Public Service Authority; and 

Southern Company Services, Inc. 

Pacific Gas and Electric Pacific Gas and Electric Company 

PNNL Pacific Northwest National Laboratory 

PJM PJM Interconnection, LLC 

Portland General Electric Portland General Electric Company 

Powerex Powerex Corporation 

PSEG Companies Public Service Electric and Gas Company; 

PSEG Power LLC; PSEG Energy Resources & 

Trade LLC 

Public Interest Organizations Center for Energy Efficiency & Renewable 

Technologies; Environmental Defense Fund; 

Fresh Energy; Natural Resources Defense 

Council; Northwest Energy Coalition; Office of 

the Ohio Consumers’ Counsel; Project for 
Docket No. RM10-11-000 - 105 - 

Sustainable FERC Energy Policy; and Western 

Grid Group 

Public Power Council Franklin County Public Utility District; PNGC 

Power; Northwest Requirements Utilities; and 

Western Montana Gas & Electric Cooperative 

Public Service of New Mexico Public Service Company of New Mexico 

Puget Puget Sound Energy, Inc. 

SMUD Sacramento Municipal Utility District 

Salt River Project Salt River Project Agricultural Improvement 

and Power District 

San Diego Gas & Electric San Diego Gas & Electric Company 

Sempra Sempra Generation 

Six Cities Cities of Anaheim, Azusa, Banning, Colton, 

Pasadena, and Riverside, California 

Snohomish County PUD Public Utility District No. 1 of Snohomish 

County, Washington 

SEIA Solar Energy Industries Association 

Southern California Edison Southern California Edison Company 

Southern Southern Company Services, Inc. 

SWTC & AEP Southwest Transmission Cooperative, Inc. and 

Arizona Electric Power Cooperative, Inc. 

Summit Wind Summit Wind LLC 

Sunflower and Mid-Kansas Sunflower Electric Power Corporation and MidKansas Electric Company, LLC 

Symbiotics Symbiotics, LLC 

Tacoma Power City of Tacoma, Department of Public Utilities, 
Docket No. RM10-11-000 - 106 - 

Light Division (Washington) 

Transmission Access Policy Study Transmission Access Policy Study 

Group Group 

Transmission Agency of Northern Transmission Agency of Northern 

California California 

Turlock Irrigation Turlock Irrigation District 

University of Delaware University of Delaware Center for Carbon-Free 

Power Integration 

US Bureau of Reclamation United States Bureau of Reclamation 

Utility Economic Engineers Utility Economic Engineers 

Viridity Energy Viridity Energy, Inc. 

Wärtsilä Wärtsilä North America 

WECC Western Electricity Coordinating Council

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; 

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 

Westar Westar Energy, Inc. and Kansas Gas and 

Electric Company 

Western Farmers Western Farmers Electric Cooperative 

Western Grid Western Grid Group 

Western Power Trading Forum Western Power Trading Forum 
Docket No. RM10-11-000 - 107 - 

William Short William P. Short III & Lisa Linowes 

Wyoming Power Producers Wyoming Power Producers Coalition 

Xcel Xcel Energy Services Inc. 
Docket No. RM10-11-000 - 108 - 

Appendix B: Proposed inserts to the Pro Forma Open Access Transmission Tariff 

The Commission proposes to amend and/or add the following sections of the pro forma

OATT: 

 a. Table of Contents (Add Section 3.8, Generator Regulation and Frequency 

Response Service, and Schedule 10, Generator Regulation and Frequency Response 

Service) 

b. Section 3 

 c. Section 3.8 

 d. Section 13.8 

 e. Section 14.6 

 f. Schedule 10 

 3 Ancillary Services 

Ancillary Services are needed with transmission service to maintain 

reliability within and among the Control Areas affected by the transmission 

service. The Transmission Provider is required to provide (or offer to arrange with 

the local Control Area operator as discussed below), and the Transmission 

Customer is required to purchase, the following Ancillary Services (i) Scheduling, 

System Control and Dispatch, and (ii) Reactive Supply and Voltage Control from 

Generation or Other Sources. 

The Transmission Provider is required to offer to provide (or offer to 

arrange with the local Control Area operator as discussed below) the following 
Docket No. RM10-11-000 - 109 - 

Ancillary Services only to the Transmission Customer serving load within the 

Transmission Provider's Control Area (i) Regulation and Frequency Response, (ii) 

Energy Imbalance, (iii) Operating Reserve - Spinning, and (iv) Operating Reserve 

– Supplemental. The Transmission Customer serving load within the 

Transmission Provider’s Control Area is required to acquire these Ancillary 

Services, whether from the Transmission Provider, from a third party, or by selfsupply. 

The Transmission Provider is required to provide (or offer to arrange with 

the local Control Area Operator as discussed below), to the extent it is physically 

feasible to do so from its resources or from resources available to it, Generator 

Regulation and Frequency Response Service and Generator Imbalance Service 

when Transmission Service is used to deliver energy from a generator located 

within its Control Area. The Transmission Customer using Transmission Service 

to deliver energy from a generator located within the Transmission Provider’s 

Control Area is required to acquire Generator Regulation and Frequency Response 

Service and Generator Imbalance Service, whether from the Transmission 

Provider, from a third party, or by self-supply. 

The Transmission Customer may not decline the Transmission Provider’s 

offer of Ancillary Services unless it demonstrates that it has acquired the Ancillary 

Services from another source. The Transmission Customer must list in its 

Application which Ancillary Services it will purchase from the Transmission 
Docket No. RM10-11-000 - 110 - 

Provider. A Transmission Customer that exceeds its firm reserved capacity at any 

Point of Receipt or Point of Delivery or an Eligible Customer that uses 

Transmission Service at a Point of Receipt or Point of Delivery that it has not 

reserved is required to pay for all of the Ancillary Services identified in this 

section that were provided by the Transmission Provider associated with the 

unreserved service. The Transmission Customer or Eligible Customer will pay for 

Ancillary Services based on the amount of transmission service it used but did not 

reserve. 

If the Transmission Provider is a public utility providing transmission 

service but is not a Control Area operator, it may be unable to provide some or all 

of the Ancillary Services. In this case, the Transmission Provider can fulfill its 

obligation to provide Ancillary Services by acting as the Transmission Customer’s 

agent to secure these Ancillary Services from the Control Area operator. The 

Transmission Customer may elect to: (i) have the Transmission Provider act as its 

agent, (ii) secure the Ancillary Services directly from the Control Area operator, or 

(iii) secure the Ancillary Services (discussed in Schedules 3, 4, 5, 6, 9 and 10) 

from a third party or by self-supply when technically feasible. 

The Transmission Provider shall specify the rate treatment and all related 

terms and conditions in the event of an unauthorized use of Ancillary Services by 

the Transmission Customer. 

The specific Ancillary Services, prices and/or compensation methods are 
Docket No. RM10-11-000 - 111 - 

described on the Schedules that are attached to and made a part of the Tariff. 

Three principal requirements apply to discounts for Ancillary Services provided 

by the Transmission Provider in conjunction with its provision of transmission 

service as follows: (1) any offer of a discount made by the Transmission Provider 

must be announced to all Eligible Customers solely by posting on the OASIS, (2) 

any customer-initiated requests for discounts (including requests for use by one’s 

wholesale merchant or an affiliate’s use) must occur solely by posting on the 

OASIS, and (3) once a discount is negotiated, details must be immediately posted 

on the OASIS. A discount agreed upon for an Ancillary Service must be offered 

for the same period to all Eligible Customers on the Transmission Provider’s 

system. Sections 3.1 through 3.8 below list the eight Ancillary Services. 

3.8 Generator Regulation and Frequency Response Service: 

Where applicable the rates and/or methodology are described in Schedule 10. 

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 
Docket No. RM10-11-000 - 112 - 

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 fifteen (15) minutes 

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 
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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 

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 up to fifteen (15) minutes 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. 
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SCHEDULE 10

Generator Regulation and Frequency Response Service 

 Generator Regulation and Frequency Response Service is necessary to provide for 

the continuous balancing of resources (generation and interchange) with load and for 

maintaining scheduled Interconnection frequency at sixty cycles per second (60 Hz). 

Generator Regulation and Frequency Response Service is accomplished by committing 

on-line generation whose output is raised or lowered (predominantly through the use of 

automatic generating control equipment) and/or by other non-generation resources 

capable of providing this service as necessary to follow the moment-by-moment changes 

in generation output. The obligation to maintain this balance between resources and load 

lies with the Transmission Provider (or the Balancing Authority that performs this 

function for the Transmission Provider). The Transmission Provider (or the Balancing 

Authority that performs this function for the Transmission Provider) must offer this 

service when Transmission Service is used to deliver energy from a generator physically 

or electrically located within its Balancing Authority Area. The Transmission Customer 

or generator must either purchase this service from the Transmission Provider or make 

alternative comparable arrangements, which may include use of non-generation resources 

or processes capable of providing this service, to satisfy its Generator Regulation and 

Frequency Response Service obligation. The amount of and charges for Generator 

Regulation and Frequency Response Service are set forth below. To the extent the 
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Balancing Authority performs this service for the Transmission Provider, charges to the 

Transmission Customer or generator are to reflect only a pass-through of the costs 

charged to the Transmission Provider by that Balancing Authority. 
Docket No. RM10-11-000 - 116 - 

Appendix C: Proposed inserts to the 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 other operational data to the Transmission 

Provider to the extent necessary for the Transmission Provider’s development and 

deployment of power production forecasts for 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 
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atmospheric pressure. The Interconnection Customer with a Variable Energy Resource 

having solar as the energy source, at a minimum, will be required to provide the 

Transmission Provider with temperature, atmospheric pressure, and cloud cover. 

Additional meteorological data requirements for any Interconnection Customer whose 

Generating Facility is a Variable Energy Resource will require a showing by the 

Transmission Provider that such data is needed to develop and deploy a power production 

forecast for that Variable Energy Resource, or is mutually agreed to by the 

Interconnection Customer and the Transmission Provider. The exact specifications of the 

data to be provided by the Interconnection Customer to the Transmission Provider 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. 

The Interconnection Customer whose Generating Facility is a Variable Energy Resource 

shall submit operational data to the Transmission Provider regarding all unanticipated 

outages that reduce the generating capability of the Variable Energy Resource by 1 MW 

or more for 15 minutes or more.