75336 Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 

1 Integration of Variable Energy Resources, 130 

FERC ¶ 61,053 (2010) (Integrating VERs NOI). 

2For the purpose of this proceeding, the term 

variable energy resource (VER) refers to an electric 

generating facility that is characterized by an energy 

source that: (1) Is renewable; (2) cannot be stored 

by the facility owner or operator; and (3) has 

variability that is beyond the control of the facility 

owner or operator. This includes, for example, 

wind, solar thermal and photovoltaic, and 

hydrokinetic generating facilities. 

DEPARTMENT OF ENERGY 

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: 

require public utility transmission 

providers to offer intra-hourly 

transmission scheduling; 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 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. 

DATES: Comments are due January 31, 

2011. 

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 Web site, 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), 

Office of General Counsel—Energy 

Markets, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502– 

8288, Andrea.Hilliard@ferc.gov. 

SUPPLEMENTARY INFORMATION: 

TABLE OF CONTENTS

Paragraph/ 

Nos. 

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

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

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

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

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

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

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

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

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

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

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

IX. Regulatory Flexibility Act Analysis ....................................................................................................................................................... 113 

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

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

Regulatory Text 

Appendix A: List of Short Names of Commenters on the Federal Energy Regulatory Commission’s Notice of Inquiry on Integration 

of Variable Energy Resources—Docket No. RM10–11–000, January 2010 

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

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

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 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 


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3See, 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). 

4Preventing Undue Discrimination and 

Preference in Transmission Service, Order No. 890, 

FERC Stats. & Regs. ¶ 31,241, at P 5, order on reh’g, 

Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 

(2007), order on reh’g, Order No. 890–B, 123 FERC 

¶ 61,299 (2008), order on reh’g, Order No. 890–C, 

126 FERC ¶ 61,228, order on clarification, Order 

No. 890–D, 129 FERC ¶ 61,126 (2009). 

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

P 663 (requiring that generator imbalance 

provisions account for the special circumstances 

presented by intermittent generators). 

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

P 690. 

7 16 U.S.C. 824d, 824e. 

8Promoting 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). 

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 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 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-bycase 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. 

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 

themselves.8 Concluding that unduly 

discriminatory and anticompetitive 

practices existed in the electric industry 

and that, absent Commission action, 

such practices would increase as 

competitive pressures in the industry 

grew, the Commission in Order No. 888 

required all public utility transmission 

providers that own, control, or operate 

transmission facilities used in interstate 

commerce to have on file an open 

access, non-discriminatory transmission 

tariff that contains minimum terms and 

conditions of non-discriminatory 

service. As relevant here, 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 


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75338 Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 

9Standardization 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 (DC Cir. 2007). 

10 Id. 

11 Id. 

12Order No. 2003–A, FERC Stats. & Regs. 

¶ 31,160 at P 407 n.85. 

13 Id. 

14 Interconnection for Wind Energy, Order No. 

661, FERC Stats. & Regs. ¶ 31,186 (2005), order on 

reh’g, Order No. 661–A, FERC Stats. & Regs. 

¶ 31,198 (2005). 

15Order No. 890, FERC Stats. & Regs. ¶ 31,241, 

order on reh’g, Order No. 890–A, FERC Stats. & 

Regs. ¶ 31,261, order on reh’g, Order No. 890–B, 123 

FERC ¶ 61,299, order on reh’g, Order No. 890–C, 

126 FERC ¶ 61,228, order on clarification, Order 

No. 890–D, 129 FERC ¶ 61,126. 

16Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 435–43. 

17 Id. P 663–72. 

18 Id. P 911–15. 

19 Integrating VERs NOI, 130 FERC ¶ 61,053 at 

P 9. 

20 Id. 

21 Id. P 12. 

22See Appendix A. 

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

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

25See, e.g., NorthWestern at 4–6; Idaho Power at 

2–4; Puget at 2. 

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

Edison at 7. 

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

28Southern at 4–10; EEI at 2; ColumbiaGrid at 4– 

5. 

29As part of this Proposed Rule, the Commission 

is also proposing a minor revision to 18 CFR 35.28. 

To date, when amending its regulations concerning 

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. 

that there was a pressing need for a 

single set of procedures and a single, 

uniformly applicable interconnection 

agreement for large generator 

interconnections.9 Accordingly, the 

Commission adopted standard 

procedures (the Large Generator 

Interconnection Procedures or LGIP) 

and a standard agreement (the Large 

Generator Interconnection Agreement or 

LGIA) for the interconnection of 

generation resources greater than 20 

MW.10 These reforms were designed to 

minimize opportunities for undue 

discrimination and expedite the 

development of new generation, while 

protecting reliability and ensuring that 

rates are just and reasonable.11

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

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 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 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 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 


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30See 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). 

31Ryan 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_report.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-mkt-ovr/som-rpt-2009.pdf. 

33Solar Energy Industries Ass’n, US Solar 

Industry Year in Review 2009, at 2, available at 

http://seia.org/galleries/default-file/2009%20

Solar%20Industry%20Year%20in%20Review.pdf. 

34See 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/othrrnw-rps.pdf). 

35 26 U.S.C. 45. 

36American Recovery and Reinvestment Tax Act 

of 2009, Pub. L. 111–5, sec. 1101, 123 Stat. 115, 319 

(2009). 

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

38Transmission 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). 

39See, 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). 

40See North American Elec. Reliability Corp., 

Accommodating High Levels of Variable Generation 

(2009), available at http://www.nerc.com/files/ 

IVGTF_Report_041609.pdf. 

41See 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). 

VERs. The Commission anticipates that 

the proposed operational and pricing 

reforms will result in a more efficient 

utilization of all generation, nongeneration,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 capacity being 

brought on line—in 2009, new wind 

generating capacity rose to 9,994 MW, 

or 39 percent of all newly installed 

generating capacity, bringing total wind 

generating capacity to more than 35,000 

MW.31 In addition to this existing 

capacity, another 85 GW of wind 

generating capacity has been proposed 

to be on line by the end of 2012.32 The 

amount of new solar generating capacity 

also has increased in recent years, 

adding 351 MW in 2008 and 481 MW 

in 2009, bringing the total solar 

generating capacity to more than 2,000 

MW.33

14. The Commission expects the 

number of VERs, both in real numbers 

and as a percentage of total generation 

capacity, to continue to grow. Indicators 

of this anticipated growth are suggested 

by the significant number of public 

policies, both at the state and federal 

levels, encouraging the development of 

VERs. In the Integrating VERs NOI, the 

Commission noted that as of December 

2009, 30 states and the District of 

Columbia had a renewable portfolio 

standard.34 Moreover, federal tax 

policies that provide incentives to the 

development of renewable generation 

facilities have been in place for a 

number of years. For example, the 

federal production tax credit, which has 

been in effect intermittently since the 

early 1990s, provides an inflationadjusted 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 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. 

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 American Electric Reliability 

Corporation (NERC) through the 

Integration of Variable Generation Task 

Force 40 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 


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75340 Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 

42Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 689 n.401, order on reh’g, Order No. 890–A, FERC 

Stats. & Regs. ¶ 31,261 at P 313. More recently, the 

Commission clarified transmission providers’ 

obligation to offer generator regulation service by 

rejecting a transmission provider’s proposal to 

require VERs exporting out of the transmission 

provider’s balancing authority area to provide or 

arrange for their own generator regulation capacity. 

See NorthWestern, 129 FERC ¶ 61,116 at P 24 

(finding that the proposal to disclaim the obligation 

to provide the capacity reserves necessary to 

providing generator imbalance service would be 

inconsistent with the transmission provider’s 

obligation to offer generator imbalance service set 

forth in the pro forma OATT). 

43See, e.g., Joint Initiative at 7–12 (explaining 

ongoing efforts in the West to develop a dynamic 

scheduling system and intra-hour transaction 

accelerator platform to facilitate transactions among 

balancing authorities); ISO/RTO Council at 44 

(indicating that ISOs and RTOs have begun to 

integrate centralized forecasting into reliability 

commitment processes); NERC, Integration of 

Variable Generation Task Force, 2009–2011 Work 

Plan (2009), available at http://www.nerc.com/ 

docs/pc/ivgtf/IVGTF_Work_%20Plan_111309.pdf 

(detailing on-going efforts to establish mechanisms 

to calculate the capacity associated with VERs). See 

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). 

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, 

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 case-by-case 

approach to filings by public utility 

transmission providers seeking to 

recover the costs of additional 

regulation reserves associated with 

providing generator imbalance 

service.42 This existing policy, however, 

has led to uncertainty and allows the 

potential for undue discrimination. To 

prevent this uncertainty and potential 

undue discrimination, we believe it is 

appropriate now to propose a generic 

generator regulation reserve rate 

schedule that will delineate the rights 

and obligations of public utility 

transmission providers and customers 

with respect to the provision of this 

service. 

22. Additionally, the Commission is 

proposing guidelines under which 

public utility transmission providers 

may assess generator regulation reserve 

charges to transmission customers. Such 

charges must be established based on 

traditional cost causation principles. To 

the extent a public utility transmission 

provider proposes to require 

transmission customers who are 

delivering energy from VERs to 

purchase, or otherwise account for, a 

different volume of generator regulation 

reserves than it proposes to charge 

transmission customers delivering 

energy from other generating resources, 

such differing volumes must be shown 

to be commensurate with the variability 

that VERs exhibit on the transmission 

provider’s system. Furthermore, the 

public utility transmission provider 

must show that it has adopted measures 

to mitigate the total amount of 

regulation reserve necessary to manage 

the variability through the 

implementation of VER power 

production forecasting and intra-hourly 

scheduling. This mitigation requirement 

will help to ensure that the rates for this 

service are just and reasonable. 

23. Through these three proposals, the 

Commission seeks to reform operational 

protocols that present barriers to the 

integration of VERs and to ensure the 

cost of integrating new resources, such 

as VERs, are not unnecessarily inflated 

by inappropriate systems and processes. 

While the proposed reforms focus on 

discrete operational protocols, they are 

integrally related and should be 

understood as complementary parts of a 

package. The Commission believes this 

set of reforms will help to level the 

playing field for all types of resources, 

provide much-needed clarification as to 

the roles and responsibilities of public 

utility transmission providers and 

transmission customers, and bring 

greater transparency and efficiency to 

existing system operations. As described 

in more detail below, the Commission 

believes that these proposed rules are 

necessary to remedy undue 

discrimination in existing transmission 

system operations and to ensure that 

rates for Commission-jurisdictional 

services are just and reasonable. 

24. As should be clear from the scope 

of this Proposed Rule, the Commission 

is not proposing to address the 

additional issues identified in the 

Integrating VERs NOI at this time. Upon 

review of the comments, the 

Commission believes that further study 

of many issues identified in the 

Integrating VERs NOI is required. In 

addition, a number of parties are 

actively developing solutions to address 

issues raised in the Integrating VERs 

NOI.43 Therefore, in keeping with the 

suggestion of a number of commenters 

to allow individual regions to continue 

to develop solutions to the challenges 

unique to their characteristics and 

resources, and in recognition of 

commenters who seek Commission 

engagement on these issues, the 

Commission proposes to instruct its 

staff to monitor and conduct outreach 

with industry stakeholders to keep 

abreast of developments. 

V. Proposed Reforms 

A. Intra-Hourly Scheduling 

25. Outside of regions that have an 

RTO or ISO, resources typically 


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44Section 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. 

45 Integrating VERs NOI, 130 FERC ¶ 61,053 at 

P 18. 

46 Id. 

47 Id. P 19. 

48 Id. 

49 Id. P 18–21. 

50AWEA at 38 (citing M. Milligan & B. Kirby, 

Impact of Balancing Area Size, Obligation Sharing, 

and Ramping Capability on Wind Integration, 

27–29 (2007), available at http://www.nrel.gov/ 

wind/systemsintegration/pdfs/2007/ 

milligan_wind_integration_impacts.pdf). 

51AWEA at 20 (citing Avista Corp., Wind 

Integration Study (2007), available at http:// 

www.uwig.org/AvistaWindIntegrationStudy.pdf). 

52AWEA at 20 (citing Presentation by Bart 

McManus, Bonneville. Large Wind Integration 

Challenges and Solutions for Operations/System 

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). 

53Bonneville at 6. 

54WECC at P 6. 

55Ramp events are instances where the generating 

facility experiences a significant change in 

electrical output. 

56EEI at 9. 

57NERC at 16. 

58 Joint Initiative at 3. 

59NERC at 17–18. 

60AWEA at 16. 

61 Id. at 38. 

62 Id. at 40. 

63 Iberdrola at 10. 

64Southern California Edison at 10–11. 

65Southern California Edison at 12. 

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 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 transmission 

scheduling flexibility, such as intrahour 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 intrahour transmission scheduling. AWEA 

states that shorter scheduling intervals 

will allow generators to provide 

inexpensively much of the flexibility 

that is currently being provided by 

expensive regulation reserves.50 AWEA 

points out that the Avista Wind 

Integration Study similarly found wind 

integration costs would be reduced by 

40–60 percent by moving from hourly to 

intra-hourly dispatch intervals.51

Additionally, AWEA asserts that 

Bonneville has publicly stated that wind 

integration costs on its system would be 

reduced by 80 percent by moving from 

hourly schedules to intra-hourly 

schedules.52 Bonneville states that intrahour 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 events 55 and 

variability, provide more accurate 

scheduling, reduce the reliance on 

regulating reserves and make it easier to 

meet NERC CPS–2.56 NERC claims that 

while additional system flexibility can 

come from many sources, such as the 

availability of flexible conventional 

resources and non-conventional 

resources such as storage and demand 

response programs, an additional 

contributor to greater system flexibility 

includes shorter scheduling intervals, 

for both within a balancing authority 

area and between balancing authority 

areas.57 Joint Initiative states that 

allowing transmission customers to 

schedule transactions within an 

operating hour increases operating 

flexibility for VERs and the rest of the 

system.58 NERC claims that the ideal 

scheduling increments to achieve 

optimum flexibility while still meeting 

relevant reliability requirements may be 

between five and fifteen minutes; 

however, this depends on system 

characteristics, the type of VERs present 

on the system, and the level of VER 

penetration.59

30. AWEA argues that hourly 

scheduling practices have a much 

greater negative impact on VERs than on 

traditional dispatchable resources and 

that it is within the Commission’s 

statutory duty to address these issues of 

discrimination.60 AWEA notes that 

shorter scheduling intervals will yield 

significant benefits even on 

transmission systems without wind 

energy, as there is significant intra-hour 

variability in load, as well as in the 

output of non-VER resources when they 

experience forced outages or otherwise 

fail to provide their scheduled output.61

AWEA also contends that moving to 

shorter dispatch intervals will actually 

improve power system reliability by 

freeing up additional system flexibility 

that is currently underutilized.62

Iberdrola argues that the Commission 

should modify 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 


emcdonald on DSK2BSOYB1PROD with PROPOSALS4
75342 Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 

66EEI at 8. 

67 Id. at 9. 

68Bonneville 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). 

72SMUD at 20. 

73AWEA at 39. 

74 Id. 

75Entergy at 2. 

76 Id. 

77 Id. 

78 Id. 

79 Id. 

80NorthWestern at 14. 

81NRECA at 30 (citing BAL (Resource and 

Demand Balancing), INT (Interchange Scheduling 

and Coordination), IRO (Interconnection Reliability 

Operations and Coordination), and MOD (Modeling, 

Data, and Analysis) Standards). 

82NRECA at 28. 

83 Id. at 29. 

84 Id. 

85 Id. 

86Southern at 11. 

87Altresco at 5–6. 

88Southern at 11. 

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 

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 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 intra-hour 

schedules/settlements, (2) OATT 

revisions necessary to accommodate 

transmission reservations for periods of 

less than a full clock hour, and (3) 

possible staffing increases to handle the 

greater number of transactions.74

34. Entergy states that it moved from 

hourly scheduling to twenty-minute 

anytime-scheduling several years ago.75

According to Entergy, no changes to the 

OATT, e-Tag or NERC rules were 

required.76 Entergy states that its 

scheduling systems were significantly 

modified to implement this additional 

flexibility, but such changes have 

proven to be manageable to date. 

Entergy cautions that if intra-hour 

scheduling is mandated, the burden on 

the system operators may increase, such 

as when there are reliability issues on 

the system.77 Entergy explains that at 

these times, system operators would 

have to handle intra-hour schedules and 

reliability issues simultaneously.78

Therefore, Entergy asks the Commission 

to proceed carefully and consider 

differences among balancing authority 

areas, in terms of software, manpower, 

and scheduling work load, before 

mandating intra-hour scheduling.79

Similarly, Northwestern argues that 

system automation will be necessary to 

allow much greater number of schedules 

and transmission service requests to be 

processed without impacting 

reliability.80 National Rural Electric 

Cooperative Association (NRECA) 

claims that a number of NERC standards 

would need to be reviewed to determine 

the impacts of a move towards flexible 

scheduling.81

35. Smaller public utility 

transmission providers highlight 

challenges with respect to their size and 

explain that the implementation of 

intra-hour scheduling may be infeasible 

for certain entities. NRECA indicates 

that for smaller systems, 

implementation of intra-hour 

scheduling would be a significant 

additional burden and could require 

substantial costs in software 

modification.82 NRECA explains that 

while changes to infrastructure required 

for trading may be absorbed by large 

entities, smaller cooperatives would be 

affected disproportionately because of 

their inability to spread the costs over 

the large volume of trade.83 NRECA 

claims that in any cost-benefit analysis, 

it is less likely that smaller entities will 

benefit, even over time, especially 

where they lack a large customer base, 

which is the case for many rural electric 

cooperatives.84 Consequently, NRECA 

contends that intra-hour scheduling is 

simply infeasible for some of its 

members at this time.85

36. Finally, some commenters oppose 

the implementation of intra-hour 

scheduling for their regions regardless 

of cost or whether the Commission 

allows for regional differences. 

Generally, these commenters base their 

objections on two grounds. First, 

commenters under the impression that 

the intra-hour scheduling would be 

available only to transmission 

customers using VERs argue that it 

would be unfair to afford scheduling 

opportunities to one class of 

transmission customers and not others, 

such as those utilizing conventional 

resources. Southern argues that there 

should not be any unique or special 

scheduling protocols applicable to only 

certain types of generation.86 Second, 

commenters argue that the 

responsibility for scheduling efficiency 

should fall on VERs. These commenters 

generally argue that VERs should be 

required to maintain the accuracy of 

their schedules and should not expect 

public utility transmission providers to 

change scheduling practices that have 

worked in the past. Altresco states that 

maintaining scheduling practices is 

essential to the reliability of the grid, 

and that VERs should take 

responsibility for the reliability impact 

of the variability of their resource.87

Southern states that all generators 

(including VERs) should be responsible 

for providing accurate schedules and 

that the risk and responsibility for 

forecasting availability should always be 

the generator’s responsibility and 

should not be shifted to the public 

utility transmission provider or system 

operator.88


emcdonald on DSK2BSOYB1PROD with PROPOSALS4
Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 75343 

89The Commission’s proposed reform allows for 

intra-hour scheduling adjustments; it does not 

propose changes to the hourly transmission service 

reservations provided in the OATT. 

90NERC at 17–18. 

91NERC at 20, AWEA at 40, EEI at 29, Southern 

California Edison at 11–12, CalWEA at 7, Pacific 

Gas and Electric at 6, NaturEner at 11, and Wa ̈rtsila ̈

at 7. 

92See Integrating VERs NOI, 130 FERC ¶ 61,053 

at P 18. 

93Bonneville at 45. 

94Order No. 888, FERC Stats. & Regs. at 31,703– 

704. 

95See 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). 

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 reliability.91 As such, we do not 

believe, as NRECA suggests, that an 

independent review of NERC standards 

is necessary to making this proposed 

reform. However, the Commission seeks 

comment on the issue to ensure that 

there is no inconsistency among 

relevant NERC standards and the 

proposed intra-hour scheduling tariff 

reform. 

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 real-time energy 

markets rely on reserve services, which 

are provided under a number of existing 

ancillary service rate schedules.94

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 providers 

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 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 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, 


emcdonald on DSK2BSOYB1PROD with PROPOSALS4
75344 Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 

96NERC, 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. 

98NERC at 6. 

99Bernhard 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. 

100National Renewable Energy Laboratory, 

Western Wind and Solar Integration Study ES–18 

(2010), available at http://www.nrel.gov/wind/ 

systemsintegration/wwsis.html. 

101Charles 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_A-S_Study_Final_Report.pdf. 

103Enernex Corporation, 2006 Minnesota Wind 

Integration Study 73–74 (2006), available at 

http://www.uwig.org/windrpt_vol%201.pdf. 

104Cal. Indep. Sys. Operator Corp., 98 FERC 

¶ 61,327, order on compliance, 99 FERC ¶ 61,309 

(2002). 

105New York Indep. Sys. Operator, Inc., 123 

FERC ¶ 61,267, at P 13–14 (2008). 

106 Xcel at 3. 

107 Id. 

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, 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 intrahour 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 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 de-commit 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 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 SPP 101 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

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 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, stateof-the-art wind output prediction 

tools.106 Xcel explains that while these 

tools require large amounts of 

meteorological information and turbinelevel real-time 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 


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108 Integrating VERs NOI, 130 FERC ¶ 61,053 at 

P 14–17. 

109Argonne National Lab at 1. 

110NREL at 9. 

111NERC at 3. 

112 Id. at 20. 

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

114 ISO/RTO Council at 17. 

115Bonneville at 40, G&T Cooperative at 12, 

NaturEner at 6. 

116NERC at 5. 

117CAISO at 22, Iberdrola at 17, ISO–NE at 13, 

Xcel at 6–7. 

118CAISO at 13. 

119 Id. at 12. 

120SEIA at 20. 

121APS at 6. 

122AWEA at 35. 

123Bonneville at 40. 

124SEIA at 20. 

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. 

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-ofthe-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-today 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 highrisk 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

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 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 others 117 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 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 

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 


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125See 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.’’). 

126Bonneville at 5, Calpine at 13, M–S–R Public 

Power Agency at 4, NEPOOL at 7. 

127See supra P 45–46. 

128 ISO/RTO Council at 16. 

129 Iberdrola at 14–18, NERC at 3 & 7, and NREL 

at 3. 

130TOP–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). 

131See Pro Forma LGIA Article 22 (setting forth 

the confidentiality provisions applicable to data 

exchanged through the interconnection process). 

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, 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 comments 126 and other 

technical analysis 127 indicating that the 

failure to consider VER power 

production forecasts in the hour-ahead, 

intra-day, day-ahead, and monthly time 

frames may result in an overprocurement 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 procedures 128

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 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 

Standards 130 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-ofthe-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

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 windbased 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 resourcespecific data requirements contained in 

individual LGIAs must be negotiated on 

a not unduly discriminatory basis. 

62. With respect to operational data, 

the Commission proposes to revise the 

pro forma LGIA to require 


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132Cal. Indep. Sys. Operator Corp., 131 FERC 

¶ 61,087 (2010). 

133 Id. P 42. 

134 Id. P 45. 

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). 

136See NERC, Accommodating High Levels of 

Variable Generation 13–14 (2009), available at 

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

IVGTF_Report_041609.pdf. 

137Order No. 661, FERC Stats. & Regs. ¶ 31,186 

at P 120; Order No. 2003, FERC Stats. & Regs. 

¶ 31,146 at P 910. 

138Order No. 888, FERC Stats. & Regs. at 31,703– 

04. 

139 Id. 

140 Id. at 31,707–708 (referencing Promoting 

Wholesale Competition Through Open Access NonDiscriminatory 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)). 

141The 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. 

142 Id. at 31,717. 

143 Id. 

144 Id. at 31,708. 

145 Id. at 31,717. 

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 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 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. 

C. Generator Regulation ServiceCapacity 

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 area 141 to serve load in that 

area.142 However, the Commission did 

not require public utility transmission 

providers to offer Regulation Service for 

transmission service out of or through 

the transmission provider’s balancing 

authority area to serve load in another 

balancing authority area.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 


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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. 

147Order No. 890, FERC Stats. & Regs. ¶ 31,241 

at P 634. 

148 Id. 

149 Id. P 663. 

150 Id. P 667. 

151See 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. 

153Refers to costs associated with capacity used 

to provide generator imbalance reserve service that 

otherwise are not recovered through Schedule 3. 

154Order No. 890, FERC Stats. & Regs. ¶ 31,241 

at n. 401. 

155Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 

at P 313. 

156See, e.g., Entergy Services Inc., 120 FERC 

¶ 61,042, at P 62–66 (2007); Sierra Pac. Res. 

Operating Cos., 125 FERC ¶ 61,026 (2008). 

157See, 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. 

158NorthWestern, 129 FERC ¶ 61,116, order on 

reh’g, 131 FERC ¶ 61,202. 

159NorthWestern, 129 FERC ¶ 61,116 at P 24. 

160Westar, 130 FERC ¶ 61,215 at P 1. 

161 Id. P 35–36. 

162 Id. P 35. 

163Puget Sound, 132 FERC ¶ 61,128 at P 4. 

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 

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 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 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 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 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 


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164 Id. P 35. 

165 Integrating VERs NOI, 130 FERC ¶ 62,053 at 

P 35. 

166 Id. 

167 Id. P 36. 

168AWEA at 15–16. 

169 Id. at 67. 

170 Id. See also Iberdrola at 37. 

171NextEra 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). 

172NERC at 22–23. 

173 Xcel at 38. 

174See 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. 

175Bonneville at 84. 

176 Id. at 2. 

177 Id. at 94. 

178 Id. at 3. 

179 Id. at 22. 

180 Id. at 4. 

181Bonneville 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)). 

representation of the costs incurred in 

providing a following service to wind 

resources.164

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 abovedescribed 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 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, 

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 costeffective means of supplying reserves of 

VERs and that balancing authorities 

should be permitted 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 intra-hourly. 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 

strive to facilitate options (e.g., selfsupply 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 


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75350 Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 

182See NorthWestern at 30. 

183 Id. 

184PUD No. 2 Grant County at 4, Bonneville at 

25–26. 

185EEI at 20–21. 

186 Id. at 21–22. 

187NREL at 15. 

188Contingency reserves are reserves held and 

deployed in the event of an unexpected failure or 

outage of a generation, non-generation or 

transmission resource. 

189NaturEner at 21. 

190Westar at 27, Puget at 13, Exelon 15–16, Xcel 

at 36–37, Grant PUD at 25–26. 

191NorthWestern, 129 FERC ¶ 61,116 at P 27. 

192See id. P 24. 

193Order 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. 

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-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

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 reserves 188 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 

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 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-bycase 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 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 


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194See 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). 

195See 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). 

196See 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. 

197See Order No. 890–A, FERC Stats. & Regs. 

¶ 31,261 at P 288. 198Westar at 7, NorthWestern 5–6. 

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 

balancing authority area 194 or by selfsupplying 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 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. 

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 

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 


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75352 Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 

199Westar, 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. 

200AWEA at 67. See also Iberdrola at 37. 

201See, e.g., NREL at 16–17. 

202See, e.g., Bonneville at 100, Xcel at 41, Nevada 

Power at 7–8. 

203Schedule 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.’’ 

204See Appendix B and C for the proposed pro 

forma OATT and LGIA provisions consistent with 

this Proposed Rule. 

reserves than 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 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. 

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 nearterm 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 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 nondiscriminatory manner while remailning consistent with NERC 

Reliability Standards. 

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 


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205Order No. 888, FERC Stats. & Regs. at 31,760– 

763. 206The Commission expects that in any 

subsequent filing to establish a volumetric 

requirement in Schedule 10, public utility 

transmission providers will address how 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. 

208 44 U.S.C. 3507(d) (2006). 

209 5 CFR 1320.11 (2010). 

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 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 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 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. 

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 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: 


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210Regulations 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). 

211 18 CFR 380.4(a)(15) (2010). 

212 5 U.S.C. 601–612 (2006). 

Data collection 

FERC 516 

Number of 

respondents 

Number of 

responses 

Hours per 

response Total annual hours 

[1] [2] [3] [1 × 2 × 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. 

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 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 Commissionjurisdictional 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 intra-hourly 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., 

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 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 


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213A ‘‘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.’’ 

214Credit Reforms in Organized Wholesale 

Electric Markets, 133 FERC ¶ 61,060, at P 184 

(2010). 215Standard 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. 

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 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 

with 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. 

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 January 31, 2011. 

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. 

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 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 Web site during 

normal business hours from FERC 

Online Support at 202–502–6652 (toll 

free at 1–866–208–3676) or e-mail 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 CFR Part 35 

Electric power rates; Electric utilities; 

Reporting and recordkeeping 

requirements. 

By direction of the Commission. 

Kimberly D. Bose, 

Secretary. 

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) introductory text 

is revised. 

b. Paragraphs (c)(1)(i), (ii), (iii), 

(c)(1)(v) and (c)(1)(vi) are revised. 

c. Paragraphs (c)(3) introductory text 

and (c)(3)(ii) are revised. 

d. Paragraphs (c)(4) is revised. 

e. Paragraph (d) is revised. 

f. Paragraphs (e)(1)introductory text, 

(e)(1)(ii) and (e)(2) are revised. 

h. Paragraphs (f)(1) introductory text 

and (f)(1)(i) are revised. 

i. Paragraphs (f)(1)(ii) through 

(f)(1)(iv) are removed and (f)(1)(ii) is 

reserved. 

j. Paragraph (f)(3) is revised. 

k. Paragraph (f)(4) is removed. 

§ 35.28 Non-discriminatory open access 

transmission tariff. 

* * * * * 

(c) * * * 

(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 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. 


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(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 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 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. 

(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 Commission-approved 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) * * * 

(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) * * * 

(1) Every public utility that is 

required to have on file a nondiscriminatory 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. 

(i) Any public utility that seeks a 

deviation from the standard 


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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. 

(ii) [Reserved] 

* * * * * 

(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. 

* * * * * 

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. 

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. 1 of 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. 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 North 

America.

E.ON Climate & Renewables North 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. 

Idaho Power .................................... Idaho Power Company. 

Imperial Irrigation District ................ Imperial Irrigation District (CA). 


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Short name or acronym Commenter 

Independent Power Producers Coalition—West.Arizona Competitive Power Alliance; 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 

Owners.

Central Hudson Gas & Electric Corporation; 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 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. 

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 

Electricity.

New England States’ Committee on 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. 

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 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. 


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Short name or acronym Commenter 

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 Mid-Kansas Electric Company, LLC. 

Symbiotics ....................................... Symbiotics, LLC. 

Tacoma Power ................................ City of Tacoma, Department of Public Utilities, Light Division (Washington). 

Transmission Access Policy Study 

Group.

Transmission Access Policy Study Group. 

Transmission Agency of Northern 

California.

Transmission Agency of Northern 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. 

Wa ̈rtsila ̈ ........................................... Wa ̈rtsila ̈ 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; TriState 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. 

William Short ................................... William P. Short III & Lisa Linowes. 

Wyoming Power Producers ............ Wyoming Power Producers Coalition. 

Xcel ................................................. Xcel Energy Services Inc. 

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 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 self-supply. 

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 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 


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75360 Federal Register / Vol. 75, No. 231 / Thursday, December 2, 2010 / Proposed Rules 

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 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 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-tohour 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-ToPoint Transmission Service 

Schedules for Non-Firm Point-To-Point 

Transmission Service must be submitted to 

the Transmission Provider no later than 2 

p.m. [or a reasonable time that is generally 

accepted in the region and is consistently 

adhered to by the Transmission Provider] of 

the day prior to commencement of such 

service. Schedules submitted after 2 p.m. will 

be accommodated, if practicable. Hour-tohour 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-tohour 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. 

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 

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. 

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 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 


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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. 

[FR Doc. 2010–29574 Filed 12–1–10; 8:45 am] 

BILLING CODE 6717–01–P 


emcdonald on DSK2BSOYB1PROD with PROPOSALS4