[Federal Register Volume 75, Number 231 (Thursday, December 2, 2010)]
[Proposed Rules]
[Pages 75336-75361]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-29574]
[[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
Federal Register / Vol. 75 , No. 231 / Thursday, December 2, 2010 /
Proposed Rules
[[Page 75336]]
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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, [email protected];
Andrea Hilliard (Legal Information), Office of General Counsel--Energy
Markets, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8288, [email protected].
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
[[Page 75337]]
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
[[Page 75338]]
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.
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\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).
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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).
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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.
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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.
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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\
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\49\ Id. P 18-21.
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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.
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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\
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\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.
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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.
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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\
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\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\
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\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.
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\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.
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\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&SectionTitle=Energy+%26+Environment.
\102\ GE Energy, Analysis of Wind Generation Impact on ERCOT
Ancillary Services Requirements 9-7 (2008), available at http://www.uwig.org/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.
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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\
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\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.
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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\
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\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.
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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.
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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\
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\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\
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\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.
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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.
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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\
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\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.
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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.
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\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.
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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.
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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.
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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.
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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).
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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.
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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.
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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.
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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.
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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\
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\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.
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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.
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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:
[email protected], 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: [email protected]. 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
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at
[email protected].
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
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specifications of the data to be provided by the Interconnection
Customer to the Transmission Provider shall be made taking into
account the size and configuration of the Variable Energy Resource,
its characteristics, location, and its importance in maintaining
generation resource adequacy and transmission system reliability in
its area.
The Interconnection Customer whose Generating Facility is a
Variable Energy Resource shall submit operational data to the
Transmission Provider regarding all unanticipated outages that
reduce the generating capability of the Variable Energy Resource by
1 MW or more for 15 minutes or more.
[FR Doc. 2010-29574 Filed 12-1-10; 8:45 am]
BILLING CODE 6717-01-P