Document ID: FERC-2010-1799-0001
Agency: ferc
Document Type: Proposed Rule
Title: Integration of Variable Energy Resources
Posted Date: 2010-12-02T05:00Z

[Federal Register: December 2, 2010 (Volume 75, Number 231)]
[Proposed Rules]               
[Page 75335-75361]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr02de10-9]                         

[[Page 75335]]

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Part IV

Department of Energy

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 Federal Energy Regulatory Commission

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18 CFR Part 35

Integration of Variable Energy Resources; Proposed Rule

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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.

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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
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                                                              Paragraph/
                                                                 Nos.
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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
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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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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).
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    \1\ Integration of Variable Energy Resources, 130 FERC ] 61,053 
(2010) (Integrating VERs NOI).
    \2\ For the purpose of this proceeding, the term variable energy 
resource (VER) refers to an electric generating facility that is 
characterized by an energy source that: (1) Is renewable; (2) cannot 
be stored by the facility owner or operator; and (3) has variability 
that is beyond the control of the facility owner or operator. This 
includes, for example, wind, solar thermal and photovoltaic, and 
hydrokinetic generating facilities.
    \3\ See, e.g., Joint Initiative at 1-12 (describing 
collaborative efforts in the Western Interconnection for high-value 
and cost-effective regional products involving increased 
coordination among different transmission providers), SMUD at 8-12 
(describing SMUD's participation in regional efforts in California 
and the Northwest), ISO/RTO Council at 12-18 (discussing ISO/RTO 
efforts to develop and incorporate VER forecasting into their system 
operations).
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    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.
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    \4\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241, 
at P 5, order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 
31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 
(2008), order on reh'g, Order No. 890-C, 126 FERC ] 61,228, order on 
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
    \5\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 663 
(requiring that generator imbalance provisions account for the 
special circumstances presented by intermittent generators).
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    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-by-case approach to 
generator regulation service in Order No. 890,\6\ the increased 
interest as evidenced by commenters and the number of Commission 
filings related to this service has led us to consider a generic 
approach to the provision of generator regulation service, such as the 
one proposed here.
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    \6\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 690.
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    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\
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    \7\ 16 U.S.C. 824d, 824e.
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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.
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    \8\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,682 (1996), order 
on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on 
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, 
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub 
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 
(2002).
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    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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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\
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    \9\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P 11 
(2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 
31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 
31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. 
] 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. 
Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007).
    \10\ Id.
    \11\ Id.
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    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\
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    \12\ Order No. 2003-A, FERC Stats. & Regs. ] 31,160 at P 407 
n.85.
    \13\ Id.
    \14\ Interconnection for Wind Energy, Order No. 661, FERC Stats. 
& Regs. ] 31,186 (2005), order on reh'g, Order No. 661-A, FERC 
Stats. & Regs. ] 31,198 (2005).
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    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\
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    \15\ Order No. 890, FERC Stats. & Regs. ] 31,241, order on 
reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261, order on 
reh'g, Order No. 890-B, 123 FERC ] 61,299, order on reh'g, Order No. 
890-C, 126 FERC ] 61,228, order on clarification, Order No. 890-D, 
129 FERC ] 61,126.
    \16\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 435-43.
    \17\ Id. P 663-72.
    \18\ Id. P 911-15.
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    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\
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    \19\ Integrating VERs NOI, 130 FERC ] 61,053 at P 9.
    \20\ Id.
    \21\ Id. P 12.
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    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\
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    \22\ See Appendix A.
    \23\ AWEA at 2; Iberdrola at 8-10; NextEra 2-8.
    \24\ Southern at 3; EEI at 2; ISO/RTO Council at 2.
    \25\ See, e.g., NorthWestern at 4-6; Idaho Power at 2-4; Puget 
at 2.
    \26\ See, e.g., NV Energy at 2, 6; Southern California Edison at 
7.
    \27\ See, e.g., Southern at 19.
    \28\ Southern at 4-10; EEI at 2; ColumbiaGrid at 4-5.
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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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VERs. The Commission anticipates that the proposed operational and 
pricing reforms will result in a more efficient utilization of all 
generation, non-generation,\30\ and transmission resources and lay the 
basis for continued development, including the possibility of 
innovative solutions, such as efforts by the Joint Initiative in the 
West.
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    \29\ As 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.
    \30\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 888 
(modifying Schedules 2, 3, 4, 5, 6, and 9 of the pro forma OATT to 
indicate that the ancillary services provided in those rate 
schedules may be provided by generating units as well as other non-
generation resources such as demand response where appropriate).
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    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\
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    \31\ Ryan Wiser & Mark Bolinger, Lawrence Berkeley National 
Laboratory, 2009 Wind Technologies Market Report 3-5 (2010), 
available at http://www1.eere.energy.gov/windandhydro/pdfs/2009_
wind_technologies_market_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.
    \33\ Solar Energy Industries Ass'n, US Solar Industry Year in 
Review 2009, at 2, available at http://seia.org/galleries/default-
file/2009%20Solar%20Industry%20Year%20in%20Review.pdf.
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    14. The Commission expects the number of VERs, both in real numbers 
and as a percentage of total generation capacity, to continue to grow. 
Indicators of this anticipated growth are suggested by the significant 
number of public policies, both at the state and federal levels, 
encouraging the development of VERs. In the Integrating VERs NOI, the 
Commission noted that as of December 2009, 30 states and the District 
of Columbia had a renewable portfolio standard.\34\ Moreover, federal 
tax policies that provide incentives to the development of renewable 
generation facilities have been in place for a number of years. For 
example, the federal production tax credit, which has been in effect 
intermittently since the early 1990s, provides an inflation-adjusted 
credit for power produced from VERs and other renewable resources.\35\ 
In February 2009, the American Recovery and Reinvestment Act (ARRA) not 
only extended the production tax credit for a period of three 
additional years,\36\ but also instituted an investment tax credit, 
which allows developers of certain renewable generation facilities to 
take a 30 percent cash grant in lieu of the production tax credit.\37\ 
Other federal policies that provide incentives to renewable generation 
facilities include accelerated depreciation of certain renewable 
generation facilities and loan guarantee programs.
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    \34\ See Integrating VERs NOI, 130 FERC ] 61,053 at P 2 (citing 
Div. of Energy Market Oversight, Fed. Energy Regulatory Comm'n, 
Renewable Power and Energy Efficiency Market: Renewable Portfolio 
Standards 1 (2009), available at http://www.ferc.gov/market-
oversight/othr-mkts/renew/othr-rnw-rps.pdf).
    \35\ 26 U.S.C. 45.
    \36\ American Recovery and Reinvestment Tax Act of 2009, Pub. L. 
111-5, sec. 1101, 123 Stat. 115, 319 (2009).
    \37\ Id. sec. 1102, 123 Stat. 115, 319-20.
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    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.
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    \38\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, 131 FERC ] 61,253, at P 36 
(2010) (Transmission Planning and Cost Allocation Proposed Rule).
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    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.
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    \39\ See, e.g., NorthWestern Corp., 129 FERC ] 61,116 (2009) 
(NorthWestern), order on reh'g, 131 FERC ] 61,202 (2010); Westar 
Energy Inc., 130 FERC ] 61,215 (2010) (Westar); Cal. Indep. Sys. 
Operator Corp., 131 FERC ] 61,087 (2010); Puget Sound Energy, Inc., 
132 FERC ] 61,128 (2010) (Puget Sound).
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    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

[[Page 75340]]

proposed herein can and should be implemented in a way that complements 
ongoing stakeholder proceedings.
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    \40\ See North American Elec. Reliability Corp., Accommodating 
High Levels of Variable Generation (2009), available at http://
www.nerc.com/files/IVGTF_Report_041609.pdf.
    \41\ See Joint Initiative at 3-11 (describing projects currently 
being developed by members of Columbia Grid, Northern Tier 
Transmission Group and WestConnect such as an Intra-Hour Transaction 
Accelerator Platform and a Dynamic Scheduling System).
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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.
---------------------------------------------------------------------------

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

    22. Additionally, the Commission is proposing guidelines under 
which public utility transmission providers may assess generator 
regulation reserve charges to transmission customers. Such charges must 
be established based on traditional cost causation principles. To the 
extent a public utility transmission provider proposes to require 
transmission customers who are delivering energy from VERs to purchase, 
or otherwise account for, a different volume of generator regulation 
reserves than it proposes to charge transmission customers delivering 
energy from other generating resources, such differing volumes must be 
shown to be commensurate with the variability that VERs exhibit on the 
transmission provider's system. Furthermore, the public utility 
transmission provider must show that it has adopted measures to 
mitigate the total amount of regulation reserve necessary to manage the 
variability through the implementation of VER power production 
forecasting and intra-hourly scheduling. This mitigation requirement 
will help to ensure that the rates for this service are just and 
reasonable.
    23. Through these three proposals, the Commission seeks to reform 
operational protocols that present barriers to the integration of VERs 
and to ensure the cost of integrating new resources, such as VERs, are 
not unnecessarily inflated by inappropriate systems and processes. 
While the proposed reforms focus on discrete operational protocols, 
they are integrally related and should be understood as complementary 
parts of a package. The Commission believes this set of reforms will 
help to level the playing field for all types of resources, provide 
much-needed clarification as to the roles and responsibilities of 
public utility transmission providers and transmission customers, and 
bring greater transparency and efficiency to existing system 
operations. As described in more detail below, the Commission believes 
that these proposed rules are necessary to remedy undue discrimination 
in existing transmission system operations and to ensure that rates for 
Commission-jurisdictional services are just and reasonable.
    24. As should be clear from the scope of this Proposed Rule, the 
Commission is not proposing to address the additional issues identified 
in the Integrating VERs NOI at this time. Upon review of the comments, 
the Commission believes that further study of many issues identified in 
the Integrating VERs NOI is required. In addition, a number of parties 
are actively developing solutions to address issues raised in the 
Integrating VERs NOI.\43\ Therefore, in keeping with the suggestion of 
a number of commenters to allow individual regions to continue to 
develop solutions to the challenges unique to their characteristics and 
resources, and in recognition of commenters who seek Commission 
engagement on these issues, the Commission proposes to instruct its 
staff to monitor and conduct outreach with industry stakeholders to 
keep abreast of developments.
---------------------------------------------------------------------------

    \43\ See, e.g., Joint Initiative at 7-12 (explaining ongoing 
efforts in the West to develop a dynamic scheduling system and 
intra-hour transaction accelerator platform to facilitate 
transactions among balancing authorities); ISO/RTO Council at 44 
(indicating that ISOs and RTOs have begun to integrate centralized 
forecasting into reliability commitment processes); NERC, 
Integration of Variable Generation Task Force, 2009-2011 Work Plan 
(2009), available at http://www.nerc.com/docs/pc/ivgtf/IVGTF_Work_
%20Plan_111309.pdf (detailing on-going efforts to establish 
mechanisms to calculate the capacity associated with VERs). See 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).
---------------------------------------------------------------------------

V. Proposed Reforms

A. Intra-Hourly Scheduling

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

[[Page 75341]]

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\
---------------------------------------------------------------------------

    \44\ Section 13.8 of the pro forma OATT requires transmission 
customers to schedule use of firm point-to-point transmission 
service by 10:00 a.m. the day prior to operation. That section also 
gives the transmission provider the discretion to accept schedule 
changes no later than 20 minutes prior to the operating hour.
    \45\ Integrating VERs NOI, 130 FERC ] 61,053 at P 18.
    \46\ Id.
---------------------------------------------------------------------------

    26. The Commission further explained that because transmission 
schedules are typically set 20-30 minutes ahead of the hour, the 
forecast of a VER's output (upon which its schedule is based) may be 90 
minutes old by the end of the operating hour.\47\ As a result, because 
of a resource's limited ability to adjust its schedules during the 
hour, the operational flexibility of all resources on the transmission 
provider's system may not be utilized.\48\
---------------------------------------------------------------------------

    \47\ Id. P 19.
    \48\ Id.
---------------------------------------------------------------------------

    27. Therefore, the Commission sought to explore whether the 
retention of existing transmission scheduling practices had caused the 
rates for reserves to become unjust and unreasonable by inhibiting the 
ability of VERs to establish operationally-viable schedules and 
preventing public utility transmission providers from utilizing the 
flexibility of their systems. More specifically, the Commission sought 
to explore whether greater transmission scheduling flexibility, such as 
intra-hour scheduling or other improvements in the scheduling 
procedures, might offer the potential for greater efficiency in 
dispatching all resources. For instance, the Commission noted the 
potential for more efficient dispatch if the magnitude of schedule 
deviations could be reduced, better anticipated, and/or planned for 
more precisely.\49\
---------------------------------------------------------------------------

    \49\ Id. P 18-21.
---------------------------------------------------------------------------

1. Comments
    28. Most commenters recognize the benefits and support the 
implementation of some form of intra-hour transmission scheduling. AWEA 
states that shorter scheduling intervals will allow generators to 
provide inexpensively much of the flexibility that is currently being 
provided by expensive regulation reserves.\50\ AWEA points out that the 
Avista Wind Integration Study similarly found wind integration costs 
would be reduced by 40-60 percent by moving from hourly to intra-hourly 
dispatch intervals.\51\ Additionally, AWEA asserts that Bonneville has 
publicly stated that wind integration costs on its system would be 
reduced by 80 percent by moving from hourly schedules to intra-hourly 
schedules.\52\ Bonneville states that intra-hour scheduling has the 
potential to help better manage the costs and operational impacts of 
VER generator imbalances.\53\
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    \50\ AWEA at 38 (citing M. Milligan & B. Kirby, Impact of 
Balancing Area Size, Obligation Sharing, and Ramping Capability on 
Wind Integration, 27-29 (2007), available at http://www.nrel.gov/
wind/systemsintegration/pdfs/2007/milligan_wind_integration_
impacts.pdf).
    \51\ AWEA at 20 (citing Avista Corp., Wind Integration Study 
(2007), available at http://www.uwig.org/
AvistaWindIntegrationStudy.pdf).
    \52\ AWEA at 20 (citing Presentation by Bart McManus, 
Bonneville. Large Wind Integration Challenges and Solutions for 
Operations/System Reliability at slide 26 (Oct. 2008), available at 
http://www.uwig.org/Denver/McManus.pdf) (stating 10 minute schedule 
changes would solve approximately 80% of the issues Bonneville is 
anticipating).
    \53\ Bonneville at 6.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \54\ WECC at P 6.
    \55\ Ramp events are instances where the generating facility 
experiences a significant change in electrical output.
    \56\ EEI at 9.
    \57\ NERC at 16.
    \58\ Joint Initiative at 3.
    \59\ NERC at 17-18.
---------------------------------------------------------------------------

    30. AWEA argues that hourly scheduling practices have a much 
greater negative impact on VERs than on traditional dispatchable 
resources and that it is within the Commission's statutory duty to 
address these issues of discrimination.\60\ AWEA notes that shorter 
scheduling intervals will yield significant benefits even on 
transmission systems without wind energy, as there is significant 
intra-hour variability in load, as well as in the output of non-VER 
resources when they experience forced outages or otherwise fail to 
provide their scheduled output.\61\ AWEA also contends that moving to 
shorter dispatch intervals will actually improve power system 
reliability by freeing up additional system flexibility that is 
currently underutilized.\62\ Iberdrola argues that the Commission 
should modify 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\
---------------------------------------------------------------------------

    \60\ AWEA at 16.
    \61\ Id. at 38.
    \62\ Id. at 40.
    \63\ Iberdrola at 10.
    \64\ Southern California Edison at 10-11.
    \65\ Southern California Edison at 12.
---------------------------------------------------------------------------

    31. Many commenters, however, seek the flexibility to develop 
regional solutions without a Commission mandate that they be required 
to do so. The common reason given for this view is that each region has 
a unique mix of conventional generation resources and VERs, and each 
region should be

[[Page 75342]]

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\
---------------------------------------------------------------------------

    \66\ EEI at 8.
    \67\ Id. at 9.
    \68\ Bonneville at 44.
    \69\ ISO/RTO Council at 36.
---------------------------------------------------------------------------

    32. Additionally, several of the commenters that oppose a 
Commission mandate to implement intra-hour scheduling cite reform 
efforts that are already underway. For example, the Joint Initiative 
describes its development of model intra-hour transmission purchase and 
scheduling business practices in the Western Interconnection.\70\ The 
Joint Initiative also explains that a number of utilities in the 
Northwest have begun to implement these practices to one degree or 
another.\71\ SMUD points out that the Western Systems Power Pool 
currently seeks to develop two new service schedules that will 
accommodate VERs through the provision of reserve services and intra-
hour supplemental energy. For this reason, SMUD argues that the 
Commission should avoid taking actions where industry efforts are in 
progress to cost-effectively achieve similar goals, particularly when 
those efforts are further taking into account regional 
characteristics.\72\
---------------------------------------------------------------------------

    \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).
    \72\ SMUD at 20.
---------------------------------------------------------------------------

    33. Commenters generally recognize that the implementation process 
is not without some costs. AWEA states that the cost of transitioning 
to intra-hourly dispatch is quite modest and the bulk of these costs 
are up-front expenditures while the benefits of making the transition 
will be realized in perpetuity.\73\ AWEA explains that the costs 
associated with the transition to an intra-hourly dispatch include: (1) 
Modifications of dispatch/energy management and NERC e-Tag systems in 
order to accommodate intra-hour schedules/settlements, (2) OATT 
revisions necessary to accommodate transmission reservations for 
periods of less than a full clock hour, and (3) possible staffing 
increases to handle the greater number of transactions.\74\
---------------------------------------------------------------------------

    \73\ AWEA at 39.
    \74\ Id.
---------------------------------------------------------------------------

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

    \75\ Entergy at 2.
    \76\ Id.
    \77\ Id.
    \78\ Id.
    \79\ Id.
    \80\ NorthWestern at 14.
    \81\ NRECA at 30 (citing BAL (Resource and Demand Balancing), 
INT (Interchange Scheduling and Coordination), IRO (Interconnection 
Reliability Operations and Coordination), and MOD (Modeling, Data, 
and Analysis) Standards).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \82\ NRECA at 28.
    \83\ Id. at 29.
    \84\ Id.
    \85\ Id.
---------------------------------------------------------------------------

    36. Finally, some commenters oppose the implementation of intra-
hour scheduling for their regions regardless of cost or whether the 
Commission allows for regional differences. Generally, these commenters 
base their objections on two grounds. First, commenters under the 
impression that the intra-hour scheduling would be available only to 
transmission customers using VERs argue that it would be unfair to 
afford scheduling opportunities to one class of transmission customers 
and not others, such as those utilizing conventional resources. 
Southern argues that there should not be any unique or special 
scheduling protocols applicable to only certain types of 
generation.\86\ Second, commenters argue that the responsibility for 
scheduling efficiency should fall on VERs. These commenters generally 
argue that VERs should be required to maintain the accuracy of their 
schedules and should not expect public utility transmission providers 
to change scheduling practices that have worked in the past. Altresco 
states that maintaining scheduling practices is essential to the 
reliability of the grid, and that VERs should take responsibility for 
the reliability impact of the variability of their resource.\87\ 
Southern states that all generators (including VERs) should be 
responsible for providing accurate schedules and that the risk and 
responsibility for forecasting availability should always be the 
generator's responsibility and should not be shifted to the public 
utility transmission provider or system operator.\88\
---------------------------------------------------------------------------

    \86\ Southern at 11.
    \87\ Altresco at 5-6.
    \88\ Southern at 11.

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[[Page 75343]]

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.
---------------------------------------------------------------------------

    \89\ The Commission's proposed reform allows for intra-hour 
scheduling adjustments; it does not propose changes to the hourly 
transmission service reservations provided in the OATT.
    \90\ NERC at 17-18.
    \91\ NERC at 20, AWEA at 40, EEI at 29, Southern California 
Edison at 11-12, CalWEA at 7, Pacific Gas and Electric at 6, 
NaturEner at 11, and W[auml]rtsil[auml] at 7.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \92\ See Integrating VERs NOI, 130 FERC ] 61,053 at P 18.
    \93\ Bonneville at 45.
    \94\ Order No. 888, FERC Stats. & Regs. at 31,703-704.
---------------------------------------------------------------------------

    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,

[[Page 75344]]

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.
---------------------------------------------------------------------------

    \95\ See Joint Initiative at 5-6 (citing sub-hourly scheduling 
initiatives by the following: NV Energy, PacifiCorp, Bonneville, 
Puget, Portland General Electric, Avista Corp., Seattle City Light, 
Chelan County PUD, Grant County PUD, and Tacoma Power).
---------------------------------------------------------------------------

    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 
intra-hour transmission scheduling. To more fully understand the 
modifications that this proposed reform may require, the Commission 
seeks more detailed comment on the specific hardware, software, and 
personnel changes that are necessary to implement intra-hour 
scheduling, any additional impacts on relatively small public utility 
transmission providers, and how to best facilitate this reform for 
small public utility transmission providers.

B. Power Production Forecasting and Data Reporting

    45. Research has shown that VERs power production forecasts are 
essential in managing the variability of VERs and, equally importantly, 
the use of these forecasting methodologies enhances economic efficiency 
and allows transmission providers to 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\
---------------------------------------------------------------------------

    \96\ NERC, Integration of Variable Generation Task Force, Task 
2.1 Report: Variable Generation Power Forecasting for Operations 5 
(2010), available at http://www.nerc.com-/docs/pc/ivgtf/Task2-
1(5.20).pdf.
    \97\ Id. at 54. See also National Renewable Energy Laboratory, 
Eastern Wind Integration Study 29 (2010), available at http://
www.nrel.gov/wind/systemsintegration/pdfs/2010/ewits_final_
report.pdf.
    \98\ NERC at 6.
    \99\ Bernhard Ernst et al., Predicting the Wind, IEEE Power & 
Energy Mag., Nov.-Dec. 2007, at 78, 79, available at http://
www.awea.org/utility/pdf/04383126predicting.pdf.
    \100\ National Renewable Energy Laboratory, Western Wind and 
Solar Integration Study ES-18 (2010), available at http://
www.nrel.gov/wind/systemsintegration/wwsis.html.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \101\ Charles River Assoc., SPP WITF Wind Integration Study 6-19 
(2010), available at http://www.crai.com/consultingexpertise/
listingdetails.aspx?id=12091&tID=828&subtID=0&tertID=0&fID=34&Section
Title=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/AttchBERCOT_A-S_Study_Final_Report.pdf.
    \103\ Enernex Corporation, 2006 Minnesota Wind Integration Study 
73-74 (2006), available at http://www.uwig.org/windrpt_vol%201.pdf.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \104\ Cal. Indep. Sys. Operator Corp., 98 FERC ] 61,327, order 
on compliance, 99 FERC ] 61,309 (2002).
---------------------------------------------------------------------------

    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, state-of-the-art wind output prediction tools.\106\ 
Xcel explains that while these tools require large amounts of 
meteorological information and turbine-level real-time operational 
data, migrating to this methodology has proven to be beneficial in 
terms of economics and reliability.\107\
---------------------------------------------------------------------------

    \105\ New York Indep. Sys. Operator, Inc., 123 FERC ] 61,267, at 
P 13-14 (2008).
    \106\ Xcel at 3.
    \107\ Id.
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    49. In light of these and other acknowledgements of the benefits

[[Page 75345]]

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.
---------------------------------------------------------------------------

    \108\ Integrating VERs NOI, 130 FERC ] 61,053 at P 14-17.
---------------------------------------------------------------------------

1. Comments
    50. In response to the Integrating VERs NOI, commenters filed 
detailed accounts of the current state of VER power production 
forecasting, and the necessary steps to incorporate state-of-the-art 
forecasting into system operations. Argonne National Lab's research 
indicates that increased levels of VERs will necessitate the 
incorporation of power production forecasting in unit commitment 
analyses to maintain system reliability.\109\ NREL adds that ignoring 
VER power production forecasting during the unit commitment process may 
result in the commitment of too much or too little generating capacity 
and potentially generate economic losses over time.\110\ NERC states 
that VER power production forecasts must be integrated into day-to-day 
reliability analyses and operations to ensure that system operators and 
market participants can create operating plans and procure necessary 
resources to keep supply and demand in balance on a real-time 
basis.\111\ NERC explains that the goal of power production forecasting 
should be to identify high-risk periods where procurement of additional 
flexibility or reserves is justified to maintain system balance and 
reduce the commitment of expensive reserves when there is little risk 
of them being needed for reliability.\112\ 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\
---------------------------------------------------------------------------

    \109\ Argonne National Lab at 1.
    \110\ NREL at 9.
    \111\ NERC at 3.
    \112\ Id. at 20.
    \113\ AWEA at 23, Iberdrola at 19, NERC at 7.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \114\ ISO/RTO Council at 17.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    53. NERC \116\ 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\
---------------------------------------------------------------------------

    \116\ NERC at 5.
    \117\ CAISO at 22, Iberdrola at 17, ISO-NE at 13, Xcel at 6-7.
    \118\ CAISO at 13.
    \119\ Id. at 12.
    \120\ SEIA at 20.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \121\ APS at 6.
    \122\ AWEA at 35.
    \123\ Bonneville at 40.
    \124\ SEIA at 20.
---------------------------------------------------------------------------

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

[[Page 75346]]

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\
---------------------------------------------------------------------------

    \125\ See NERC, Accommodating High Levels of Variable Generation 
54 (2009), available at http://www.nerc.com/files/IVGTF_Report_
041609.pdf. (``[I]n many areas where wind power has not reached high 
penetration levels, uncertainty associated with the wind power has 
normally been less than that of demand uncertainty * * *. 
Consequently, power system operators have been able to accommodate 
current levels of wind plant integration and the associated 
uncertainty with little or no effort.'').
---------------------------------------------------------------------------

    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 over-procurement of reserves, leading in turn to rates 
that may be unjust, unreasonable, and unduly discriminatory to VERs. 
Moreover, the Commission believes that the current ISO/RTO use of day-
ahead, hour-ahead, and even intra-hour VER power production forecasts 
in unit commitment and reliability assessment analyses and dispatch 
procedures \128\ demonstrates the benefits to be gained from 
incorporating these tools into system operations.
---------------------------------------------------------------------------

    \126\ Bonneville at 5, Calpine at 13, M-S-R Public Power Agency 
at 4, NEPOOL at 7.
    \127\ See supra P 45-46.
    \128\ ISO/RTO Council at 16.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \129\ Iberdrola at 14-18, NERC at 3 & 7, and NREL at 3.
---------------------------------------------------------------------------

    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-of-the-art power production forecasting tools. 
This proposal builds upon existing Commission data sharing requirements 
by outlining specific meteorological and operational data necessary to 
develop power production forecasts. The Commission also preliminarily 
finds that the pro forma LGIA includes adequate confidentiality 
protections for sensitive data obtained from the VERs.\131\
---------------------------------------------------------------------------

    \130\ TOP-001, R7.1 (generator outage); TOP-002-2, R14, 15 
(changes in output capability and seven day production forecasts); 
TOP-003-1 R1-3 (outage information); TOP-006-2 (monitoring system 
conditions); and IRO-004, R4 (generation, operating reserve 
projections).
    \131\ See Pro Forma LGIA Article 22 (setting forth the 
confidentiality provisions applicable to data exchanged through the 
interconnection process).
---------------------------------------------------------------------------

    61. The Commission proposes revisions to the LGIA that will result 
in different types of meteorological information being provided by 
interconnection customers based on the type of VER they own and/or 
operate. In order to enable the most accurate power production 
forecasts, the proposed revision to the LGIA would require that such 
data be transmitted from the interconnection customer to the public 
utility transmission provider at or near real-time. The Commission 
proposes to revise the pro forma LGIA to require interconnection 
customers with wind-based VERs to provide public utility transmission 
providers with site specific meteorological data including, but not 
limited to: Temperature, wind speed, wind direction, and atmospheric 
pressure. The Commission proposes to revise the pro forma LGIA to 
require interconnection customers with solar-based VERs to provide 
public utility transmission providers with site specific meteorological 
data including, but not limited to: Temperature, atmospheric pressure, 
and cloud cover. The Commission recognizes that different forecasts may 
require meteorological instruments to be located at hub height, up-wind 
of resources, or at ground level. However, the Commission will refrain 
from proposing specific requirements in this respect, and instead 
proposes to allow the public utility transmission provider and 
interconnection customer to negotiate these details taking into account 
the size and configuration of the VER facility, its characteristics, 
location, and its importance in maintaining generation resource 
adequacy and transmission system reliability in its area. The resource-
specific data requirements contained in individual LGIAs must be 
negotiated on a not unduly discriminatory basis.
    62. With respect to operational data, the Commission proposes to 
revise the pro forma LGIA to require

[[Page 75347]]

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\
---------------------------------------------------------------------------

    \132\ Cal. 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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \136\ See NERC, Accommodating High Levels of Variable Generation 
13-14 (2009), available at http://www.nerc.com/files/IVGTF_Report_
041609.pdf.
    \137\ Order No. 661, FERC Stats. & Regs. ] 31,186 at P 120; 
Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 910.
---------------------------------------------------------------------------

    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 Service-Capacity

    66. In Order No. 888, the Commission identified six ancillary 
services necessary to provide basic transmission service and required 
public utility transmission providers to offer and/or provide them to 
transmission customers.\138\ Among the ancillary services that the 
Commission required public utility transmission providers to offer were 
Regulation and Frequency Response Service (Regulation Service) and 
Energy Imbalance Service.\139\
---------------------------------------------------------------------------

    \138\ Order No. 888, FERC Stats. & Regs. at 31,703-04.
    \139\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \140\ Id. at 31,707-708 (referencing Promoting Wholesale 
Competition Through Open Access Non-Discriminatory Transmission 
Services by Public Utilities; Recovery of Stranded Costs by Public 
Utilities and Transmitting Utilities, Notice of Proposed Rulemaking 
and Supplemental Notice of Proposed Rulemaking, FERC Stats. & Regs. 
] 32,514, at 33,086 (1995)).
    \141\ The term control area, used in the pro forma OATT, has 
been superseded in the NERC Reliability Standards and industry usage 
by the term balancing authority area.
    \142\ Id. at 31,717.
    \143\ Id.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \144\ Id. at 31,708.
    \145\ Id. at 31,717.
---------------------------------------------------------------------------

    69. As described above, Regulation Service and Energy Imbalance 
Service, while different in function, are complementary services 
through which public utility transmission providers

[[Page 75348]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \147\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 634.
    \148\ Id.
    \149\ Id. P 663.
    \150\ Id. P 667.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \151\ See id. P 689 (``The Commission concludes that excluding 
additional regulation costs as a general matter is appropriate 
because much of those costs would be demand costs.'').
    \152\ Id. P 690.
    \153\ Refers to costs associated with capacity used to provide 
generator imbalance reserve service that otherwise are not recovered 
through Schedule 3.
    \154\ Order No. 890, FERC Stats. & Regs. ] 31,241 at n. 401.
    \155\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 313.
    \156\ See, e.g., Entergy Services Inc., 120 FERC ] 61,042, at P 
62-66 (2007); Sierra Pac. Res. Operating Cos., 125 FERC ] 61,026 
(2008).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \157\ See, e.g., NorthWestern, 129 FERC ] 61,116, order on 
reh'g, 131 FERC ] 61,202; Westar, 130 FERC ] 61,215; Puget Sound, 
132 FERC ] 61,128; Bonneville Power Admin., June 29, 2009 Filing, 
Docket No. EF09-2011-000.
    \158\ NorthWestern, 129 FERC ] 61,116, order on reh'g, 131 FERC 
] 61,202.
    \159\ NorthWestern, 129 FERC ] 61,116 at P 24.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \160\ Westar, 130 FERC ] 61,215 at P 1.
    \161\ Id. P 35-36.
    \162\ Id. P 35.
---------------------------------------------------------------------------

    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

[[Page 75349]]

representation of the costs incurred in providing a following service 
to wind resources.\164\
---------------------------------------------------------------------------

    \163\ Puget Sound, 132 FERC ] 61,128 at P 4.
    \164\ Id. P 35.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \165\ Integrating VERs NOI, 130 FERC ] 62,053 at P 35.
    \166\ Id.
    \167\ Id. P 36.
---------------------------------------------------------------------------

1. Comments
    76. The Commission received a number of comments on this issue, and 
different sectors of the industry hold widely divergent views on 
whether and in what manner public utility transmission providers should 
be allowed to charge VERs to account for the variability exhibited by 
those resources. The VER industry strongly opposes what it 
characterizes as ``integration charges,'' such as the above-described 
proposals from Westar and Puget Sound. AWEA views any proposal to 
assess a VER integration charge (i.e., any type of ancillary service) 
that is not justified by the variability of the actual 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\
---------------------------------------------------------------------------

    \168\ AWEA at 15-16.
    \169\ Id. at 67.
    \170\ Id. See also Iberdrola at 37.
    \171\ NextEra at 25 (explaining that while contingency reserve 
requirements are set by the single largest contingency within a 
balancing authority area, the entity that owns that contingency is 
not charged an incremental rate for those reserves).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \172\ NERC at 22-23.
---------------------------------------------------------------------------

    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 re-mainder 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\
---------------------------------------------------------------------------

    \173\ Xcel at 38.
    \174\ See Westar at 27-28. Westar contends that its OATT 
Schedule 3A approved by the Commission in Westar, 130 FERC ] 61,125 
provides a model that can be followed.
---------------------------------------------------------------------------

    79. Bonneville asserts that existing reserve products are not the 
most cost-effective means of supplying reserves of VERs and that 
balancing authorities should be permitted 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\
---------------------------------------------------------------------------

    \175\ Bonneville at 84.
    \176\ Id. at 2.
    \177\ Id. at 94.
---------------------------------------------------------------------------

    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., self-supply and dynamic transfers) 
for VER exporters to acquire balancing services from alternative 
sources.\179\ Bonneville argues that clear delineation between being a 
default supplier versus a fully compensated party to a defined 
transaction is essential to the sustainable growth of VERs.\180\
---------------------------------------------------------------------------

    \178\ Id. at 3.
    \179\ Id. at 22.
    \180\ Id. at 4.
---------------------------------------------------------------------------

    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

[[Page 75350]]

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\
---------------------------------------------------------------------------

    \181\ Bonneville at 22 (arguing that the VER owner and the 
entity that is using the VER for its own load service should have 
the fundamental planning, operational, and financial responsibility 
for ensuring that there is sufficient capacity available to manage 
the full range of variability of the VER--including regulation, load 
following, generator imbalance, and extreme tail events (large up 
and down ramp events)).
    \182\ See NorthWestern at 30.
    \183\ Id.
    \184\ PUD No. 2 Grant County at 4, Bonneville at 25-26.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \185\ EEI at 20-21.
    \186\ Id. at 21-22.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \187\ NREL at 15.
    \188\ Contingency reserves are reserves held and deployed in the 
event of an unexpected failure or outage of a generation, non-
generation or transmission resource.
    \189\ NaturEner at 21.
    \190\ Westar at 27, Puget at 13, Exelon 15-16, Xcel at 36-37, 
Grant PUD at 25-26.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \191\ NorthWestern, 129 FERC ] 61,116 at P 27.
    \192\ See id. P 24.
---------------------------------------------------------------------------

    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-by-case approach to filings by public utility transmission 
providers seeking to recover the costs of additional regulation 
reserves associated with providing generator imbalance service.\193\ 
However, in light of the increasing number and diversity of proposals 
filed with the Commission, it is appropriate to revisit the case-by-
case approach and bring a measure of consistency to the manner in which 
generation regulator reserve service is provided.
---------------------------------------------------------------------------

    \193\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 689 
n.401, order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261 
at P 313.
---------------------------------------------------------------------------

    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

[[Page 75351]]

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 self-supplying regulation reserve 
capacity from generation or non-generation resources.\195\ Furthermore, 
consistent with Order No. 890, public utility transmission providers 
may not charge transmission customers for regulation reserves under 
both Schedule 3 and proposed Schedule 10 for the same transaction.\196\
---------------------------------------------------------------------------

    \194\ See Joint Initiative at 7 (describing the development of 
the Dynamic Scheduling System in order to simplify, enhance and 
reduce the cost of dynamically scheduling resources between 
Balancing Authority Areas across the western interconnection).
    \195\ See Order No. 888, FERC Stats. & Regs. at 31,717 
(establishing the same options to dynamically schedule or self-
supply for customers subject to Schedule 3 of the pro forma OATT). 
The self-supply option would allow VERs to acquire regulating 
reserves to meet their schedules or to self-curtail according to 
specified criteria in order to reduce the amount of reserves they 
are obligated to supply or purchase. See also Order No. 890, FERC 
Stats. & Regs. ] 31,241 at P 888 (modifying Schedules 2, 3, 4, 5, 6, 
and 9 of the pro forma OATT to indicate that the services provided 
under those rate schedules may be provided by generating units as 
well as other non-generation resources such as demand response).
    \196\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 690 
(requiring transmission providers to demonstrate that any proposals 
to recover capacity costs associated with Generator Imbalance 
Service do not lead to double recovery). See also Entergy, 120 FERC 
] 61,042 at P 62-66; Sierra Pac. Res. Operating Cos., 125 FERC ] 
61,026; Westar, 130 FERC ] 61,215 at P 4.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \197\ See Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 
288.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \198\ Westar at 7, NorthWestern 5-6.
---------------------------------------------------------------------------

    95. Alternatively, where a subset of transmission customers causes 
a public utility transmission provider to procure a different per unit 
volume of regulation

[[Page 75352]]

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.
---------------------------------------------------------------------------

    \199\ Westar, 130 FERC ] 61,215 at P 35-36. In Westar, the 
proposal was an interim measure that would be in place only until 
the implementation of Southwest Power Pool's balancing area 
consolidation and ancillary services market. Id.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \200\ AWEA at 67. See also Iberdrola at 37.
---------------------------------------------------------------------------

    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 near-term by individual public utility transmission providers.
    99. In addition to the generator regulation reform proposed herein, 
commenters in response to the Integrating VERs NOI address a number of 
issues related to ancillary services reforms that do not appear ripe 
for Commission action in this proceeding. For example, commenters 
suggest the possibility of reforming rules associated with the 
provision of contingency reserves to allow the use of these reserves to 
cover infrequent but significant VER ramp events, described as ``tail'' 
events.\201\ Still other commenters suggest that the Commission revisit 
the rules applicable to VERs regarding their 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.
---------------------------------------------------------------------------

    \201\ See, e.g., NREL at 16-17.
    \202\ See, e.g., Bonneville at 100, Xcel at 41, Nevada Power at 
7-8.
---------------------------------------------------------------------------

    100. Finally, the Commission seeks comments from NERC and industry 
stakeholders on the steps needed to resolve the confusion regarding the 
use of contingency reserves to manage extreme ramp events of VERs.\203\ 
The Commission seeks comments from NERC and industry stakeholders on 
the extent to which some additional type of contingency reserve service 
(beyond the services provided under Schedule 5 and 6 of the pro forma 
OATT) would ensure that VERs are integrated into the interstate 
transmission system in a non-discriminatory manner while re-mailning 
consistent with NERC Reliability Standards.
---------------------------------------------------------------------------

    \203\ Schedule 5 (Operating Reserve--Spinning Reserve Service) 
and Schedule 6 (Operating Reserve--Supplemental Reserve Service) 
respond to contingency events. Spinning Reserve Service is used to 
serve load ``immediately in the event of a system contingency'' 
whereas Supplemental Reserve Service ``is not available immediately 
to serve load but rather within a short period of time.''
---------------------------------------------------------------------------

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

[[Page 75353]]

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.
---------------------------------------------------------------------------

    \204\ See Appendix B and C for the proposed pro forma OATT and 
LGIA provisions consistent with this Proposed Rule.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \205\ Order No. 888, FERC Stats. & Regs. at 31,760-763.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \206\ The 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \208\ 44 U.S.C. 3507(d) (2006).
    \209\ 5 CFR 1320.11 (2010).
---------------------------------------------------------------------------

    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:

[[Page 75354]]

----------------------------------------------------------------------------------------------------------------
                                       Number of       Number of
     Data collection  FERC 516        respondents      responses     Hours per  response     Total annual hours
                                               [1]             [2]  [3]..................  [1 x 2 x 3]
----------------------------------------------------------------------------------------------------------------
Conforming tariff changes to                   134               1  3....................  402.
 require intra-hourly scheduling
 or deviation request (18 CFR
 35.28(c)(1)(vi)).
Implementation of intra-hourly                 134               1  6 initial set up, 2    804 initial year, 268
 scheduling (15-minute intervals).                                   maintenance and        subsequent years.
                                                                     operation.
Addition of ancillary service rate             134               1  5....................  670.
 schedule, Schedule 10 or
 deviation request (18 CFR
 35.28(c)(1)(vi)).
Conforming changes to LGIA (for                134               1  7....................  938.
 meteorological and operational
 data provided by Interconnection
 Customers with VERs) or deviation
 request (18 CFR 35.28(f)(1)(v)).
Provision of meteorological and               270*               1  4 initial set up, 2    1,080 initial year,
 operational data by                                                 maintenance and        540 subsequent
 Interconnection Customers with                                      operation.             years.
 VERs to public utility
 transmission providers.
                                   -----------------------------------------------------------------------------
    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 Commission-
jurisdictional services are provided at rates, terms and conditions 
that are just and reasonable and not unduly discriminatory or 
preferential. This Proposed Rule seeks to achieve this goal by amending 
the pro forma OATT and LGIA to incorporate provisions that require 
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 
Sec.  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\
---------------------------------------------------------------------------

    \210\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. 
& Regs. Preambles 1986-1990 ] 30,783 (1987).
    \211\ 18 CFR 380.4(a)(15) (2010).
---------------------------------------------------------------------------

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

[[Page 75355]]

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.
---------------------------------------------------------------------------

    \212\ 5 U.S.C. 601-612 (2006).
    \213\ A ``small entity'' as referenced in the RFA refers to the 
definition provided in section 3 of the Small Business Act where a 
firm is ``small'' if, including its affiliates, it is primarily 
engaged in the generation, transmission, and/or distribution of 
electric energy for sale and its total electric output for the 
preceding fiscal year did not exceed 4 million megawatt hours. Based 
on the filers of the annual FERC Form 1 and Form 1-F, as well as the 
number of companies that have obtained waivers, we estimate that 7.5 
percent of the filers are ``small.''
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \214\ Credit Reforms in Organized Wholesale Electric Markets, 
133 FERC ] 61,060, at P 184 (2010).
    \215\ Standard generator interconnection agreements and 
procedures are segmented into large generators which are greater 
than 20 MW and small generators which are 20 MW or less. This 
proposed rule applies only to generators in the LGIA category of 
more than 20 MWs.
---------------------------------------------------------------------------

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 Sec.  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.

Sec.  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.

[[Page 75356]]

    (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 
Commission-approved 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 non-
discriminatory open access transmission tariff under this section must 
amend such tariff by adding the standard interconnection procedures and 
agreement and the standard small generator interconnection procedures 
and agreement required by Commission rulemaking proceedings 
promulgating and amending such interconnection procedures and 
agreements, or such other interconnection procedures and agreements as 
may be required by Commission rulemaking proceedings promulgating and 
amending the standard interconnection procedures and agreement and the 
standard small generator interconnection procedures and agreement.
    (i) Any public utility that seeks a deviation from the standard

[[Page 75357]]

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     E.ON Climate & Renewables North
 America.                            America.
EPSA..............................  Electric Power Supply Association.
Exelon............................  Exelon Corporation.
Federal Trade Commission..........  Federal Trade Commission.
FirstEnergy.......................  FirstEnergy Affiliates.
FIT Coalition.....................  FIT Coalition.
G&T Cooperative...................  Associated Electric Cooperative,
                                     Inc.; Basin Electric Power
                                     Cooperative; Tri-State Gas &
                                     Transmission Association, Inc.
Glenn Schleede....................  Glenn R. Schleede.
Grant PUD.........................  Public Utility District No. 2 of
                                     Grant County, Washington.
HDR Engineering...................  HDR Engineering, Inc of the
                                     Carolinas.
Iberdrola.........................  Iberdrola Renewables, Inc.
Idaho Power.......................  Idaho Power Company.
Imperial Irrigation District......  Imperial Irrigation District (CA).

[[Page 75358]]

Independent Power Producers         Arizona Competitive Power Alliance;
 Coalition--West.                    Colorado Independent Energy
                                     Association; Independent Energy
                                     Producers Association (California);
                                     New Mexico Independent Power
                                     Producers Coalition; and the
                                     Northwest & Intermountain Power
                                     Producers Coalition.
Indicated New York Transmission     Central Hudson Gas & Electric
 Owners.                             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    New England States' Committee on
 Electricity.                        Electricity.
New York ISO......................  New York Independent System
                                     Operator, Inc.
New York PSC......................  New York State Public Service
                                     Commission.
NextEra...........................  NextEra Energy Resources, LLC.
NERC..............................  North American Electric Reliability
                                     Corporation.
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.

[[Page 75359]]

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    Transmission Access Policy Study
 Group.                              Group.
Transmission Agency of Northern     Transmission Agency of Northern
 California.                         California.
Turlock Irrigation................  Turlock Irrigation District.
University of Delaware............  University of Delaware Center for
                                     Carbon-Free Power Integration.
US Bureau of Reclamation..........  United States Bureau of Reclamation.
Utility Economic Engineers........  Utility Economic Engineers.
Viridity Energy...................  Viridity Energy, Inc.
W[auml]rtsil[auml]................  W[auml]rtsil[auml] North America.
WECC..............................  Western Electricity Coordinating
                                     Council.
WestConnect.......................  Arizona Public Service Company; El
                                     Paso Electric Company, Imperial
                                     Irrigation District; NV Energy,
                                     Public Service Company of Colorado;
                                     Public Service Company of New
                                     Mexico; Sacramento Municipal
                                     Utility District; Southwest
                                     Transmission Cooperative, Inc.;
                                     Transmission Agency of Northern
                                     California; Tri-State Generation
                                     and Transmission Association, Inc.;
                                     Tucson Electric Power Company and
                                     Western Area Power Administration.
Westar............................  Westar Energy, Inc. and Kansas Gas
                                     and Electric Company.
Western Farmers...................  Western Farmers Electric
                                     Cooperative.
Western Grid......................  Western Grid Group.
Western Power Trading Forum.......  Western Power Trading Forum.
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

[[Page 75360]]

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-to-hour and intra-hour schedules equal to those furnished by 
the Receiving Party (unless reduced for losses) and shall deliver 
the capacity and energy provided by such schedules. Should the 
Transmission Customer, Delivering Party or Receiving Party revise or 
terminate any schedule, such party shall immediately notify the 
Transmission Provider, and the Transmission Provider shall have the 
right to adjust accordingly the schedule for capacity and energy to 
be received and to be delivered.

14.6 Scheduling of Non-Firm Point-To-Point Transmission Service

    Schedules for Non-Firm Point-To-Point Transmission Service must 
be submitted to the Transmission Provider no later than 2 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-to-hour and intra-
hour (four intervals consisting of fifteen minute schedules) 
schedules of energy that is to be delivered must be stated in 
increments of 1,000 kW per hour [or a reasonable increment that is 
generally accepted in the region and is consistently adhered to by 
the Transmission Provider]. Transmission Customers within the 
Transmission Provider's service area with multiple requests for 
Transmission Service at a Point of Receipt, each of which is under 
1,000 kW per hour, may consolidate their schedules at a common Point 
of Receipt into units of 1,000 kW per hour. Scheduling changes will 
be permitted up to fifteen (15) minutes before the start of the next 
scheduling interval, provided that the Delivering Party and 
Receiving Party also agree to the schedule modification. The 
Transmission Provider will furnish to the Delivering Party's system 
operator, hour-to-hour and intra-hour schedules equal to those 
furnished by the Receiving Party (unless reduced for losses) and 
shall deliver the capacity and energy provided by such schedules. 
Should the Transmission Customer, Delivering Party or Receiving 
Party revise or terminate any schedule, such party shall immediately 
notify the Transmission Provider, and the Transmission Provider 
shall have the right to adjust accordingly the schedule for capacity 
and energy to be received and to be delivered.

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

[[Page 75361]]

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