[Federal Register Volume 77, Number 135 (Friday, July 13, 2012)]
[Rules and Regulations]
[Pages 41481-41546]
[FR Doc No: 2012-15762]

Vol. 77

Friday,

No. 135

July 13, 2012

Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 35

Integration of Variable Energy Resources; Final Rule

Federal Register / Vol. 77 , No. 135 / Friday, July 13, 2012 / Rules
and Regulations

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

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

Integration of Variable Energy Resources

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission is amending the pro
forma Open Access Transmission Tariff to remove unduly discriminatory
practices and to ensure just and reasonable rates for Commission-
jurisdictional services. Specifically, this Final Rule removes barriers
to the integration of variable energy resources by requiring each
public utility transmission provider to: offer intra-hourly
transmission scheduling; and, incorporate provisions into the pro forma
Large Generator Interconnection Agreement requiring interconnection
customers whose generating facilities are variable energy resources to
provide meteorological and forced outage data to the public utility
transmission provider for the purpose of power production forecasting.

DATES: Effective Date: This rule will become effective September 11,
2012.

FOR FURTHER INFORMATION CONTACT:

Jessica L. Cockrell (Technical Information), Office of Energy Policy
and Innovation, Federal Energy Regulatory Commission, 888 First Street
NE., Washington, DC 20426,<PHONE_NUMBER>.
Andrea Hilliard (Legal Information), Office of General Counsel--Energy
Markets, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

139 FERC ] 61,246

Department of Energy

Federal Energy Regulatory Commission

Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller,
John R. Norris, Cheryl A. LaFleur, and Tony T. Clark.

Issued June 22, 2012.

                            Table of Contents

I. Introduction.............................................           1
    Background..............................................           6
II. The Need for Reform.....................................          11
    A. Commission Proposal..................................          11
    B. Comments.............................................          12
    C. Commission Determination.............................          16
III. Legal Authority To Implement Proposed Reforms..........          25
    A. Commission Proposal..................................          25
    B. Comments.............................................          26
    C. Commission Determination.............................          36
IV. Proposed Reforms........................................          51
    A. Intra-Hour Scheduling................................          51
        1. Intra-Hour Scheduling Requirement................          52
        2. Implementation of Intra-Hour Scheduling..........         114
        3. Other Issues.....................................         148
    B. Data Reporting To Support Power Production                    154
     Forecasting............................................
        1. Data Requirements................................         155
        2. Definition of VER................................         200
        3. Data Sharing.....................................         217
        4. Cost Recovery....................................         222
    C. Generator Regulation Service-Capacity................         233
        1. Schedule 10-Generator Regulation and Frequency            234
         Response Service...................................
        2. Mechanics of a Generator Regulation Charge.......         276
        3. Use of Contingency Reserves......................         336
V. Other Issues.............................................         343
    1. Regulatory Text......................................         343
    2. Market Mechanisms....................................         346
    3. Power Factor Design..................................         363
VI. Compliance..............................................         365
VII. Information Collection Statement.......................         378
VIII. Environmental Analysis................................         383
IX. Regulatory Flexibility Act Analysis.....................         384
X. Document Availability....................................         385
XI. Effective Date and Congressional Notification...........         388

I. Introduction

    1. In this Final Rule, the Commission acts under section 206 of the
Federal Power Act (FPA) to adopt reforms that will remove barriers to
the integration of variable energy resources (VER) \1\ and ensure that
the rates, terms, and conditions for Commission-jurisdictional services
provided by public utility transmission providers are just and
reasonable and not unduly discriminatory or preferential.\2\ As the
Commission noted in the Proposed Rule (75 FR 75336, December 2, 2010),
VERs are making up an increasing percentage of new generating capacity
being brought on-line.\3\ This evolution in the Nation's generation
fleet has caused the industry to reevaluate practices

developed at a time when virtually all generation on the system could
be scheduled with relative precision and when only load exhibited
significant degrees of within-hour variation. As part of this
evaluation, the Commission initiated this rulemaking proceeding to
consider its own rules and, based on the comments received, concludes
that reforms are needed in order to ensure that transmission customers
are not exposed to excessive or unduly discriminatory charges and that
public utility transmission providers have the information needed to
efficiently manage reserve-related costs.
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    \1\ As defined in the Notice of Proposed Rulemaking, a Variable
Energy Resource is a device for the production of electricity that
is characterized by an energy source that: (1) Is renewable; (2)
cannot be stored by the facility owner or operator; and (3) has
variability that is beyond the control of the facility owner or
operator. This includes, for example, wind, solar thermal and
photovoltaic, and hydrokinetic generating facilities. See
Integration of Variable Energy Resources Notice of Proposed
Rulemaking, FERC Stats. & Regs. ] 32,664, at P 64 (2010) (Proposed
Rule).
    \2\ 16 U.S.C. 824e (2006).
    \3\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 13.
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    2. Specifically, the Commission amends the pro forma Open Access
Transmission Tariff (OATT) to provide all transmission customers the
option of using more frequent transmission scheduling intervals within
each operating hour, at 15-minute intervals. There is currently no
requirement to provide transmission customers the opportunity to adjust
their transmission schedules within the hour to reflect changes in
generation output. As a result, transmission customers have no ability
under the pro forma OATT to mitigate Schedule 9 generator imbalance
charges in situations when the transmission customer knows or believes
that generation output will change within the hour. This lack of
ability to update transmission schedules within the hour can cause
charges for Schedule 9 generator imbalance service to be unjust and
unreasonable or unduly discriminatory. Accordingly, the Commission
amends the pro forma OATT to correct this deficiency.
    3. The Commission also amends the pro forma Large Generator
Interconnection Agreement (LGIA) to require new interconnection
customers whose generating facilities are VERs to provide
meteorological and forced outage data to the public utility
transmission provider with which the customer is interconnected, where
necessary for that public utility transmission provider to develop and
deploy power production forecasting. Power production forecasts can
provide public utility transmission providers with advanced knowledge
of system conditions needed to manage the variability of VER generation
through the unit commitment and dispatch process, rather than through
the deployment of reserve service, such as regulation reserves which
can be more costly. This Final Rule facilitates a public utility
transmission provider's use of power production forecasting by amending
the pro forma LGIA to require new interconnection customers whose
generating facilities are VERs to provide the underlying data necessary
for public utility transmission providers to perform such forecasts
accurately.
    4. The Commission declines, however, to modify the pro forma OATT
to include a new Schedule 10 governing generator regulation service as
set forth in the Proposed Rule. The Commission intended for the
proposed Schedule 10 to provide clarity to public utility transmission
providers and transmission customers alike by setting forth a generic
approach to the provision of generator regulation service. In response,
numerous commenters urged the Commission not to adopt a standardized
approach to generator regulation service, stressing that flexibility is
needed in the design of capacity services needed to efficiently
integrate VERs into the transmission system. The Commission agrees and,
accordingly, will continue a case-by-case approach to evaluating
proposed generator regulation service charges. To assist public utility
transmission providers and their customers in the development and
evaluation of such proposals, the Commission instead provides guidance
in response to the comments submitted.
    5. Taken together, the reforms adopted and guidance provided in
this Final Rule are intended to address issues confronting public
utility transmission providers and VERs and to allow for the more
efficient utilization of transmission and generation resources to the
benefit of all customers. This, in turn, fulfills our statutory
obligation to ensure that Commission-jurisdictional services are
provided at rates, terms, and conditions of service that are just and
reasonable and not unduly discriminatory or preferential.

Background

    6. In 1996, the Commission issued Order No. 888, which found that
it was in the economic interest of public utility transmission
providers to deny transmission service or to offer transmission service
on a basis that is inferior to what they provide to themselves.\4\
Concluding that unduly discriminatory and anticompetitive practices
existed in the electric industry and that, absent Commission action,
such practices would increase as competitive pressures in the industry
grew, the Commission in Order No. 888 required all public utility
transmission providers that own, control, or operate transmission
facilities used in interstate commerce to have on file an open access,
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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    \4\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,682 (1996), order
on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1
(2002).
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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 that there was a
pressing need for a single set of procedures and a single, uniformly
applicable interconnection agreement for large generator
interconnections.\5\ Accordingly, the Commission adopted standard
procedures (the Large Generator Interconnection Procedures or LGIP) and
a standard agreement (the LGIA) for the interconnection of generation
resources greater than 20 MW.\6\ These reforms were designed to
minimize opportunities for undue discrimination and to expedite the
development of new generation, while protecting reliability and
ensuring that rates are just and reasonable.\7\
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    \5\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P 11
(2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ]
31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ]
31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs.
] 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
    \6\ See Order No. 2003, FERC Stats. & Regs. ] 31,146.
    \7\ Id.
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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.\8\ Therefore, Commission 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.\9\ Subsequently, in Orders Nos. 661 and 661-A, the
Commission adopted a package of interconnection standards applicable to

large wind generators for inclusion in Appendix G of the LGIA.\10\
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    \8\ Order No. 2003-A, FERC Stats. & Regs. ] 31,160 at P 407 &
n.85.
    \9\ Id.
    \10\ Interconnection for Wind Energy, Order No. 661, FERC Stats.
& Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC Stats. &
Regs. ] 31,198 (2005).
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    9. In recognition of the evolving energy industry and in a further
effort to remedy the potential for undue discrimination, the Commission
returned to the pro forma OATT in Order No. 890 and implemented a
series of changes to the requirements of open access transmission
service.\11\ Among other things, the Commission adopted a set of
transmission planning principles,\12\ created a new pro forma ancillary
service schedule designed to address generator imbalances,\13\ and
instituted a new conditional firm transmission product.\14\ With regard
to imbalance charges, the Commission found that such charges should be
designed to provide appropriate incentives to keep schedules accurate
without being excessive and otherwise result in consistency in charges
between and among energy and generator imbalances.\15\ The Commission
recognized that intermittent resources, such as VERs, cannot always
accurately follow their schedules and that high penalties for
imbalances will not lessen the incentive to deviate from their
schedules. Accordingly, the Commission exempted intermittent resources
from third-tier deviation band of imbalance penalties.\16\
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    \11\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241,
order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261
(2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008),
order on reh'g, Order No. 890-C, 126 FERC ] 61,228 (2009), order on
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
    \12\ Order No. 890, FERC Stats. & Regs. ] 31,241 at PP 444-561.
In June 2011, the Commission further amended the pro forma OATT to
require, among other things, that each public utility transmission
provider participate in a regional transmission planning process
that produces a regional transmission plan and has a regional cost
allocation method for the cost of new transmission facilities
selected in a regional transmission plan for purposes of cost
allocation. Transmission Planning and Cost Allocation by
Transmission Owning and Operating Public Utilities, Order No. 1000,
176 FR 49842 (Aug. 11 2011), FERC Stats. & Regs. ] 31,323 (2011).
    \13\ Order No. 890, FERC Stats. & Regs. ] 31,241 at PP 663-72.
    \14\ Id. PP 911-15.
    \15\ Id. P 72.
    \16\ Id. P 665.
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    10. Against this backdrop, the Commission in January 2010 issued a
Notice of Inquiry in this proceeding to explore the extent to which
barriers may exist that impede the reliable and efficient integration
of VERs into the electric grid and whether reforms are needed to
eliminate those barriers.\17\ The Commission noted that the amount of
VERs is rapidly increasing, reaching a point where such resources are
becoming a significant component of the nation's energy supply
portfolio.\18\ In order to determine whether any rules, regulations,
tariffs or industry practices within the Commission's jurisdiction
hinder the reliable and efficient integration of VERs, the Commission
sought comment on a range of subject areas: (1) Power production
forecasting, including specific forecasting tools and data and
reporting requirements; (2) scheduling practices, flexibility, and
incentives for accurate scheduling of VERs; (3) forward market
structure and reliability commitment processes; (4) balancing authority
area coordination and/or consolidation; (5) suitability of reserve
products and reforms necessary to encourage the efficient use of
reserve products; (6) capacity market reforms; and (7) redispatch and
curtailment practices necessary to accommodate VERs in real time.\19\
The response from commenters was significant, with more than 135
entities submitting comments, many of which urged the Commission to
undertake basic reforms in response to the increasing number of VERs
being integrated into the system.
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    \17\ Integration of Variable Energy Resources Notice of Inquiry,
FERC Stats. & Regs. ] 35,563 (2010) (Notice of Inquiry).
    \18\ Id. P 2.
    \19\ Id. P 12.
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II. The Need for Reform

A. Commission Proposal

    11. In light of the changes occurring within the electric industry,
and based on comments submitted in response to the January 2010 Notice
of Inquiry, the Commission issued the Proposed Rule to remedy
operational and other challenges associated with VER integration that
may be causing undue discrimination and increased costs ultimately
borne by consumers. The Commission preliminarily found that the
proposed set of reforms would eliminate operational procedures that
have the de facto effect of imposing an undue burden on VERs. The
Commission stated that the proposed reforms acknowledge that existing
practices as well as the ancillary services used to manage system
variability were developed at a time when virtually all generation on
the system could be scheduled with relative precision and when only
load exhibited significant degrees of within-hour variation. In
proposing its reforms, the Commission sought to ensure that VERs are
integrated into the transmission system in a coherent and cost-
effective manner, consistent with open access principles.\20\
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    \20\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 17.
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B. Comments

    12. Commenters largely support initiation of a rulemaking
proceeding to consider potential reforms to reduce discrimination and
improve the efficiency of the transmission system.\21\ Invenergy Wind,
for example, states that the Proposed Rule reflects an important step
forward in providing the regulatory foundation that will create an
incentive for improvements in system operations and procurement
practices necessary to support the addition of renewable resources to
the nation's historical generation mix. BP Companies comment that it is
important for the Commission to provide a level playing field for wind
and solar-generated power.
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    \21\ E.g., ACSF; AEP; AWEA; Argonne National Lab; BP Companies;
Business Council; California ISO; CMUA; CEERT; Center for Rural
Affairs; Clean Line; CGC; Defenders of Wildlife; Dominion; EEI;
Environmental Defense Fund; Exelon; First Wind; Iberdrola; Idaho
Power; ITC Companies; ISO New England; Independent Power Producers
Coalition--West; ISO/RTO Council; Invenergy Wind; Large Public Power
Council; Massachusetts DPU; MidAmerican; Midwest ISO Transmission
Owners; M-S-R Public Power Agency; National Grid; NaturEner; Oregon
& New Mexico PUC; NextEra; NorthWestern; PNW Parties; PJM; Powerex;
Public Interest Organizations; RenewElec; SMUD; San Diego Gas &
Electric; SEIA; Southern California Edison; SWEA; Southwestern;
Sunflower and Mid-Kansas; Tacoma Power; Vestas; Western Farmers;
Western Grid; Xcel.
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    13. Many commenters point to the importance of the Proposed Rule in
removing market barriers to VER integration. NextEra comments that the
instant proceeding is important because VERs have been developed in
relatively modest amounts until recent years, and the existing market
rules were designed to reflect the characteristics of more traditional
generating resources (e.g., coal, natural gas and nuclear generation)
rather than VERs. NextEra contends that existing rules were aimed at
addressing the preferences and requirements of the resources and
systems in the past, rather than to anticipate future changes. CEERT
states that the Commission's initiative to remove market and
operational barriers to VERs integration and eliminate undue
discrimination against VERs is critical to making wholesale power
markets more competitive and ensuring a sustainable energy future.
    14. Iberdrola contends that this proceeding is the best opportunity
available for the federal government to encourage the responsible
development of renewable energy resources, and to avoid inadvertently
stifling the growth

of renewable energy resources in an effort to protect the economic
interests of incumbents. Similarly, NaturEner comments that the reforms
are long overdue and should be implemented without further delay and in
a manner requiring prompt compliance. This proceeding, NaturEner
states, represents substantial progress towards the elimination of
antiquated rules, requirements and processes, a significant reduction
in duplication, unnecessary expenditures and inefficient allocation of
resources, as well as an important step towards making the grid more
robust, economical, and equitable.
    15. Oregon & New Mexico PUC state that the Commission can play a
valuable role in enabling the western electricity industry to reach
state renewable energy goals at a reasonable cost to consumers by
exercising its jurisdiction in these areas. Oregon & New Mexico PUC
submit that the proposals in the Proposed Rule are an important step
toward building the necessary foundation to integrate significant
amounts of wind and solar in the West. Defenders of Wildlife similarly
contend that by establishing a new rule which encourages VER
integration, and long-term and much needed infrastructure investments
can be made today to help spur the nation's growing renewable energy
economy. ACSF states its strong support for Commission action to
integrate VERs into a smarter, cleaner, and more flexible energy grid,
whose principal design features should enable much more widespread
investment and deployment of integrated and hybrid VER generation
systems. ACSF states it is critical that the Commission exercise its
authority to develop policies that send adequate economic signals that
permit the country's most flexible, clean generation sources to provide
complementary power for VERs.

C. Commission Determination

    16. As noted above, the Commission initiated this proceeding
through the issuance of a Notice of Inquiry to obtain information on
barriers to the integration of VERs. The Commission sought to
understand the challenges associated with the large-scale integration
of VERs on the interstate transmission system and the extent to which
existing operational practices may be imposing barriers to their
integration. The Commission explained that the changing characteristics
of the nation's generation portfolio compelled a fresh look at existing
policies and practices, leading the Commission to seek comment on a
range of issues.
    17. Based on its review of comments to the Notice of Inquiry, the
Commission focused in the Proposed Rule on a series of basic reforms
regarding transmission scheduling, data reporting requirements, and
charges for generator regulation service that can and should be
implemented in the near term.\22\ The Commission explained that, taken
together, the Proposed Reforms were designed to address issues
confronting public utility transmission providers and VERs and to allow
for the more efficient utilization of transmission and generation
resources to the benefit of all customers.\23\ The Commission
acknowledged that the proposed reforms focused on discrete operational
protocols that were only a subset of the issues for which comment was
sought in the Notice of Inquiry.\24\ The Commission stated its belief
that focusing on the particular set of reforms proposed would provide a
reasonable foundation for public utility transmission providers seeking
to manage system variability associated with increased numbers of VERs
and that further study is required for many of the remaining issues
raised in the Notice of Inquiry.\25\
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    \22\ Proposed Rule, FERC Stats. & Regs ] 32,664 at P 18.
    \23\ Id. P 19.
    \24\ Id. PP 23-24.
    \25\ Id. PP 12, 24.
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    18. The Commission received more than 1900 pages of initial and
reply comments in response to the Proposed Rule. While differing in
opinion on the merits of particular aspects of the Commission's
proposal, commenters generally support the Commission's efforts to
evaluate its rules through this rulemaking to explore further
opportunities to reduce undue discrimination and reduce costs
ultimately borne by consumers through more efficient use of the
transmission system. Based on these comments, the Commission concludes
that it is appropriate to act at this time to revise the transmission
scheduling requirements of the pro forma OATT and incorporate data
reporting requirements into the pro forma LGIA, as discussed in further
detail later in this Final Rule.\26\ As discussed throughout this Final
Rule, these reforms are necessary to ensure that transmission customers
are not exposed to excessive or unduly discriminatory charges for
Schedule 9 generator imbalance service and to provide public utility
transmission providers with information necessary to more efficiently
manage reserve-related costs recovered from transmission customers
through other ancillary services charges.
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    \26\ For the reasons discussed in Schedule 10 below, the
Commission declines to standardize charges for generator regulation
service through the adoption of a generic Schedule 10 to the pro
forma OATT as suggested in the Proposed Rule.
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    19. The Commission takes this action now recognizing that the
composition of the electric generation portfolio continues to change.
VERs are making up an increasing percentage of new generating capacity
being brought on-line. New wind generating capacity accounted for 35
percent of all newly installed generating capacity from 2007-2010.\27\
As of December 2011, nearly 12,000 MW of additional wind generating
capacity has been brought online and another 8,320 MW of wind
generating capacity is currently under construction.\28\ Current
projections indicate that this expansion will continue, with the Energy
Information Agency forecasting that generation from wind power will
nearly double between 2009 and 2035.\29\ This recent and future growth
is being facilitated by developments in state and federal public
policies that encourage the expansion of VER generation.\30\
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    \27\ See American Wind Energy Association, Wind Power Outlook
2011 (Apr. 2011), available at http://www.awea.org/_cs_upload/learnabout/publications/reports/8546_1.pdf.
    \28\ American Wind Energy Association, U.S. Wind Industry Fourth
Quarter 2011 Market Report (Jan. 2012), available at http://www.awea.org/learnabout/industry_stats/upload/4Q-2011-AWEA-Public-Market-Report_1-31.pdf. In addition, the amount of new photovoltaic
generating capacity in 2011 increased by 108 percent over 2010
amounts, adding 1,855 MW of PV and bringing the total solar
generating capacity to more than 4,470 MW. Utility installations
increased by 185 percent in 2011, far more than residential or
commercial market segments. See Solar Energy Industries Ass'n, US
Solar Market Insight Report 2011 Year-in-Review Executive Summary
(Mar. 2012), available at http://www.seia.org/galleries/pdf/SMI-YIR-2011-ES.pdf.
    \29\ Annual Energy Outlook at 75, available at http://www.eia.gov/forecasts/archive/aeo11/pdf/0383(2011).pdf.
    \30\ For example, as of May 2011, 30 states and the District of
Columbia have a renewable portfolio standard or goal. FERC, Div. of
Energy Market Oversight, Renewable Power and Energy Efficiency
Market: Renewable Portfolio Standards 1 (updated May 2011),
available at http://www.ferc.gov/market-oversight/othr-mkts/renew/othr-rnw-rps.pdf). In addition, the federal production tax credit,
which has been in effect intermittently since the early 1990s,
provides an inflation-adjusted credit for power produced from VERs
and other renewable resources. 26 U.S.C. 45 (2007). In February
2009, the American Recovery and Reinvestment Act not only extended
the production tax credit for a period of three additional years but
also instituted an investment tax credit, which allows developers of
certain renewable generation facilities to take a 30 percent cash
grant in lieu of the production tax credit. American Recovery and
Reinvestment Tax Act of 2009, Pub. L. 111-5, Sec.  1101, 123 Stat.
115, 319-20 (2009). Other federal policies that provide incentives
to renewable generation facilities include accelerated depreciation
of certain renewable generation facilities and loan guarantee
programs.

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    20. As NERC has noted, higher levels of variable generation can
alter the operation and characteristics of the bulk power system.\31\
Increasing the relative amount of variable generation on a system can
increase operational uncertainty that the system operator must manage
through operating criteria, practices and procedures, including the
commitment of adequate reserves.\32\ However, many of these operational
protocols were developed for generation resources with a different set
of characteristics. For example, the hourly scheduling protocols of the
pro forma OATT reflect historical practices associated with operation
of conventional generating resources that are relatively predictable
and controllable when compared to VERs. Similarly, the interconnection
requirements of Order No. 2003 were based on the needs of traditional
synchronous generators, leading the Commission to revisit those
requirements as applied to large wind generators in Order Nos. 661 and
661-A.
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    \31\ NERC, Accommodating High Levels of Variable Generation at
8, available at http://www.nerc.com/docs/pc/ivgtf/IVGTF_Report_041609.pdf.
    \32\ Id. at 59.
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    21. In Order No. 1000, the Commission recognized that changes in
the generation mix influence the need for new transmission facilities
and, as a result, Commission policies governing transmission planning
and cost allocation.\33\ The Commission concluded there that the
increased focus on investment in new transmission projects made it
critical to implement planning and cost allocation reforms to ensure
that the transmission projects that come to fruition efficiently and
cost-effectively meet regional needs. The Commission reaches a similar
conclusion here. Changes in the generation mix and underlying public
policies influencing investment in VER generation have accentuated the
need to reform existing practices that unduly discriminate against VERs
or otherwise impair the ability of public utility transmission
providers and their customers to manage costs associated with VER
integration effectively.
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    \33\ Order No. 1000, 76 FR 49842, FERC Stats. & Regs. ] 31,323
at PP 45-46.
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    22. Specifically, we find that the adoption of intra-hour
scheduling and data reporting to support power production forecasting
will remedy undue discrimination and ensure just and reasonable rates
through more efficient utilization of transmission and generation
resources.\34\ With regard to transmission scheduling practices,
existing hourly scheduling protocols can expose transmission customers
to excessive or unduly discriminatory generator imbalance charges.
Generator imbalance charges are assessed to pay for the energy service
the transmission provider must offer to account for deviations between
a transmission customer's scheduled delivery of energy from a generator
and the amount of energy actually generated, and also to provide an
appropriate incentive for transmission customers to maintain accurate
schedules. Under Schedule 9 of the pro forma OATT, there is no
requirement to provide customers the opportunity to adjust their
transmission schedules within the hour to reflect changes in generator
output. As a result, transmission customers have no ability under the
pro forma OATT to mitigate Schedule 9 generator imbalance charges in
situations where the customer knows or believes that generation output
will change within the hour. Implementation of intra-hour scheduling
under this Final Rule will provide VERs and other transmission
customers the flexibility to adjust their transmission schedules, thus
limiting their exposure to imbalance charges. Over time, implementation
of intra-hour scheduling also will allow public utility transmission
providers to rely more on planned scheduling and dispatch procedures,
and less on reserves, to maintain overall system balance.
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    \34\ In the Proposed Rule, the Commission also proposed to
modify the pro forma OATT to include a new Schedule 10 governing
generator regulation service. For the reasons discussed elsewhere in
this Final Rule, the Commission declines to adopt that aspect of the
Proposed Rule, instead providing guidance in response to comments
submitted to assist public utility transmission providers and their
customers in the development and evaluation of proposals on a case-
by-case basis.
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    23. With regard to data reporting to support power production
forecasting, the lack of data reporting requirements can limit the
ability of public utility transmission providers to develop and deploy
power production forecasts in an effort to more efficiently manage
operating costs associated with the integration of VERs interconnecting
to their systems. Under the existing requirements of the pro forma
LGIA, public utility transmission providers are permitted to request
this information, but there is no obligation for interconnection
customers whose generating facilities are VERs to provide it.
Implementation of reporting requirements commensurate with the power
production forecasting employed by the public utility transmission
provider will allow for more accurate commitment or de-commitment of
resources providing reserves, ensuring that reserve-related charges
imposed on customers remain just and reasonable and not unduly
discriminatory or preferential. While the Commission declines to adopt
a pro forma generator regulation and frequency response service, we
note that public utility transmission providers that decide to file
with the Commission to impose such a charge should, as part of any
filing, consider the affect of the reforms we adopt in this Final Rule
when developing proposed reserve capacity costs and evaluating whether
to require different transmission customers to purchase or otherwise
account for different quantities of generator regulation reserves.
    24. Although focused on discrete issues, the implementation of
intra-hour scheduling and reporting requirements through this Final
Rule will allow for the efficient utilization of transmission and
generation resources as an increasing amount of VER generation is
integrated into the system. This in turn will ensure that the rates,
terms, and conditions for Commission-jurisdictional services provided
by public utility transmission providers are just and reasonable and
not unduly discriminatory. Our actions here are intended to build on,
rather than undermine, existing efforts at the regional level to
address VER integration. The Commission acknowledges that significant
work has been done through industry initiatives seeking to craft
regional solutions to the challenges associated with VER integration.
For example, many public utility transmission providers in the Western
Interconnection have implemented some form of transmission scheduling
at 30-minute intervals.\35\ The Commission is acting here to implement
a minimum set of requirements for all public utility transmission
providers and new interconnection customers whose generating facilities
are VERs as necessary to facilitate the efficient integration of VERs.
The Commission appreciates that these requirements go beyond some
existing activities. The Commission nonetheless concludes that the
reforms adopted herein are

necessary to ensure that Commission-jurisdictional services are being
provided at rates, terms and conditions that are just and reasonable
and not unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \35\ See, e.g., Ariz. Pub. Service Co., 137 FERC ] 61,023
(2011); NorthWestern Corp., 136 FERC ] 61,119 (2011). We note that
the Joint Initiative indicated in its comments at page 6 that its
first step in offering 30-minute scheduling ``is intended to address
unanticipated events, not to move to half-hour scheduling.'' In
addition, based on business practices posted on OASIS, some
transmission providers reserve the right to suspend 30-minute
scheduling.
---------------------------------------------------------------------------

III. Legal Authority To Implement Proposed Reforms

A. Commission Proposal

    25. In the Proposed Rule, the Commission preliminarily found that
the practice of hourly scheduling, the lack of VER power production
forecasting, and the lack of a clear mechanism to recover the cost of
providing generator regulation service may be contributing to undue
discrimination and unjust and unreasonable rates in light of the entry
and increasing presence of VERs on the transmission grid. Thus, the
Commission proposed the following three reforms that require public
utility transmission providers to: (1) Amend the pro forma OATT to
require intra-hourly transmission scheduling; (2) amend the pro forma
LGIA to incorporate provisions requiring interconnection customers
whose generating facilities are VERs to provide meteorological and
operational data to public utility transmission providers for the
purpose of improved power production forecasting; and (3) amend the pro
forma OATT to add a generic ancillary service rate schedule, Schedule
10--Generator Regulation and Frequency Response Service, in which
public utility transmission providers will offer to provide regulation
service for transmission customers using transmission service to
deliver energy from a generator located within a public utility
transmission provider's balancing authority area.\36\ The Commission
preliminarily concluded that the proposed rules are necessary to ensure
that rates for Commission-jurisdictional services are just and
reasonable and to remedy undue discrimination in existing transmission
system operations.\37\
---------------------------------------------------------------------------

    \36\ Throughout this Final Rule the term Balancing Authority is
used as defined by the North American Electric Reliability
Cooperation (NERC). NERC, Glossary of Terms, available at http://www.nerc.com/files/Glossary_of_Terms_2012January11.pdf.
    \37\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 23.
---------------------------------------------------------------------------

B. Comments

    26. Some commenters take issue with the Commission's authority to
mandate the tariff amendments contained in the Proposed Rule. With
regard to forecasting and 15-minute scheduling, EEI and Southern assert
that the Proposed Rule does not articulate a sufficient basis for
changing existing tariff-based scheduling requirements under section
206 of the FPA.\38\ Specifically, EEI and Southern question whether the
Commission is relying upon record findings to support these proposed
requirements. EEI and Southern submit that sections 205 and 206 ``are
simply parts of a single statutory scheme under which all rates are
established initially by the [public utilities], by contract or
otherwise. * * * Thus, FERC plays an essentially passive and reactive
role under section 205.'' \39\ EEI and Southern maintain that these
types of decisions should be left to public utility transmission
providers and RTOs and should be informed by regional conditions and
not dictated on a generic basis.
---------------------------------------------------------------------------

    \38\ EEI and Southern argue, for example, that the Commission
must rely upon factual, record findings to support these proposed
mandates. EEI (citing National Fuels v. FERC, 468 F.3d 831, 839-44
(D.C. Cir. 2006)); Southern (citing, e.g., National Fuels, 468 F.3d
831, 839-44).
    \39\ EEI (citing Atlantic City v. FERC, 295 F.3d 1,21 (D.C. Cir.
2002) (quoting United Gas Pipe Line Co. v. Mobile Gas Serv. Corp.,
350 U.S. 332341 (1956) and City of Winnfield v. FERC, 744 F.2d 871,
876 (D.C. Cir. 1984)); Southern (citing Atlantic City v. FERC, 295
F.3d 1,21 (D.C. Cir. 2002) (quoting United Gas Pipe Line Co. v.
Mobile Gas Serv. Corp, 350 U.S. 332341 (1956) and City of Winnfield
v. FERC, 744 F.2d 871, 876 (D.C. Cir. 1984)).
---------------------------------------------------------------------------

    27. In contrast, NextEra states that assertions that there is no
record evidence not only ignore how current rules disadvantage VERs,
but misunderstand the Commission's authority to promulgate rules of
general applicability. NextEra points out that the Commission does not
have to find that the tariffs or practices of every utility under its
jurisdiction are unjust and unreasonable in order to proceed with a
rulemaking. Rather, NextEra asserts that courts have confirmed that the
Commission is not required to make individual findings when it
exercises its statutory authority to promulgate a rule of general
applicability.
    28. Certain commenters also question the Commission's reliance in
this proceeding on its authority to remedy undue discrimination.\40\
Specifically, EEI and Southern take issue with the Commission's
conclusion that procedures (such as hourly scheduling) applied
uniformly to all transmission customers are unduly discriminatory under
the FPA when those procedures arguably have a disparate impact on
different types of transmission customers and/or place those customers
at a competitive disadvantage in wholesale markets. EEI and Southern
submit that the Commission and the DC Circuit have rejected the notion
that facially-neutral technology and customer-blind transmission
scheduling procedures are unduly discriminatory under section 205 of
the FPA because of the effects or impacts of those requirements on
different customer groups.\41\ EEI asks the Commission to clarify that
facially-neutral, technology- and customer-blind operational practices
will not be deemed unduly discriminatory solely by virtue of disparate
impact on dissimilar technologies or customers, and that the Proposed
Rule is not intended as a departure from precedent in determining undue
discrimination.
---------------------------------------------------------------------------

    \40\ E.g., Southern; EEI.
    \41\ Southern (citing Enron Power Marketing, Inc. v. FERC, 296
F.3d 1148 (D.C. Cir. 2002) (Enron)); EEI (citing Enron, 296 F.3d
1148).
---------------------------------------------------------------------------

    29. Similarly, Public Power Council questions the sufficiency of
the Commission's evidence of undue discrimination against VERs. Public
Power Council asserts that the Commission has not demonstrated that the
costs of capacity charged to VERs were not incurred for the benefit of
VERs, or would not have been incurred but for the needs of VERs, and
that the costs of capacity were not prudently incurred. Public Power
Council submits that the rules applicable to generation for the payment
of balancing capacity costs are facially neutral, as VERs require more
balancing capacity than non-variable resources. According to Public
Power Council, if a load's characteristics required extraordinary
amounts of balancing capacity, it seems unlikely that it or anyone else
would complain that the rules should be changed to reduce costs. Thus,
Public Power Council argues that a federal policy to promote renewable
generation cannot be translated into an overriding mandate to prefer
VERs.
    30. ELCON asserts, with regard to 15-minute scheduling,
forecasting, and Schedule 10 service, that the principle flaw in the
Proposed Rule is its reliance on the supposition that operating
practices favoring the dispatchability of resources are a form of
``preferential treatment,'' and therefore that non-dispatchable
resources such as VERs are being discriminated against. ELCON explains
that the proposals set forth in the Proposed Rule are costly measures
that would apply preferentially to just one class of generation--VERs--
seeking to address discrimination that does not actually exist.
    31. Southern asserts that, in instances where a single rate is
found to have disparate cost impacts upon dissimilar customers, such a
result is only considered unduly discriminatory if such differences
cannot be cost-

justified.\42\ Southern argues that existing scheduling and imbalance
practices are not unduly discriminatory against VERs. Southern explains
that VER customers pay more energy imbalance charges than others
because they impose more imbalance burdens and costs upon the
system.\43\ Similarly, ELCON maintains that the cost causation model of
cost allocation results in greater economic efficiency by retaining a
direct tie between the costs and the benefits of a given project. ELCON
argues that in the instant case, there is no tie to the costs customers
will be forced to bear.
---------------------------------------------------------------------------

    \42\ Southern (citing Ala Elec. Coop. v. FERC, 684 F.2d 20, 29
(D.C. Cir. 1982) (Alabama Power)).
    \43\ Southern further contends that VERs are not similarly
situated to dispatchable generation for sheduling and imbalance
purposes. Id. (citing City of Vernon v. FERC, 845 F.2d 1042, 1045-46
(D.C. Cir. 1988)).
---------------------------------------------------------------------------

    32. Midwest ISO Transmission Owners contend that all generation
resources should be treated on a comparable basis, and none should be
subject to undue discrimination or receive an undue preference. Midwest
ISO Transmission Owners state that in the Midwest ISO this will mean
that VERs are subject to the same requirements as existing resources
unless additional requirements are necessary to maintain
reliability.\44\ ELCON argues that the Commission should apply a
principle of ``source neutrality,'' which it contends will create a
level playing field for all alternative resources including demand
response and combined heat and power. ELCON explains that, without the
adoption of a resource planning paradigm based on source neutrality,
almost any non-traditional resource may fall prey to undue
discrimination with respect to transmission of electric energy and
sales of electric energy for resale in interstate markets.
---------------------------------------------------------------------------

    \44\ Midwest ISO Transmission Owners (referencing Proposed Rule,
FERC Stats. & Regs. ] 32,664 at PP 37, 45, 55 (stating that proposed
reforms in intra-hour scheduling and power production forecasting
can enhance reliability).
---------------------------------------------------------------------------

    33. On the contrary, NextEra argues that most market rules are not
oriented to aiding VERs, and may in fact present obstacles to VERs.
NextEra states that, even in RTO markets, the fundamental principles
around which markets are designed are day-ahead schedules, economic
dispatch, and the impact of congestion. NextEra points out that none of
these concepts are particularly applicable to VERs, which can have
difficulty producing accurate day-ahead forecasts, are not truly
dispatchable, and have limited ability to choose sites to reduce
congestion. For example, NextEra contends that while nodal
representation of generators may work best for dispatchable units, a
system that was designed around non-dispatchable VERs could include
features such as aggregation and scheduling from a portfolio of
generators that might be staggered geographically, so as to reduce
variability and forecasting errors and allow pooling of energy
imbalances and deviations.
    34. NextEra explains that when the Commission remedies unfair rules
and practices, it is not doing so to create a preference for the type
of entity that was being harmed, but rather to benefit the market and
consumers. Thus, NextEra maintains that Commission action to provide
greater flexibility, promote innovation or foster participation by new
market entrants will ultimately benefit energy markets and consumers,
even though the measure itself focuses on changes or incentives for one
type of market participant.
    35. Finally, with regard to meteorological forecasting in
particular, Southern contends that such forecasting practices are
beyond the scope of the Commission's authority. Southern states that
courts have recognized that the Commission ``is a `creature of
statute,' having no constitutional or common law existence or
authority, but only those authorities conferred upon it by Congress.''
\45\ Southern contends that public utilities have long engaged in
meteorological forecasting for load forecasting and dispatch purposes.
Southern argues that there never has been an indication that such
practices were within the scope of the Commission's jurisdiction, and
the advent of VER generation has not added such forecasting to the
scope of the Commission's authority.
---------------------------------------------------------------------------

    \45\ Southern (citing Cal. Indep. Sys. Operator Co. v. FERC, 372
F.3d 395, 398 (D.C. Cir. 2004) (citing Atlantic City Elec. Co. v.
FERC, 295 F.3d at 8)).
---------------------------------------------------------------------------

C. Commission Determination

    36. The Commission concludes that it has authority under section
206 of the FPA to adopt the reforms set forth in this Final Rule.
Section 313(b) of the FPA makes Commission findings of fact conclusive
if they are supported by substantial evidence.\46\ When applied in a
rulemaking context, ``the substantial evidence test is identical to the
familiar arbitrary and capricious standard.'' \47\ The Commission thus
must show that a ``reasonable mind might accept'' that the evidentiary
record here is ``adequate to support a conclusion,'' \48\ that this
Final Rule is needed to address barriers to the integration of VERs by
remedying challenges that may be causing undue discrimination and
increased costs ultimately borne by consumers. As explained below, the
Commission has met its burden.
---------------------------------------------------------------------------

    \46\ 16 U.S.C. 825l(b).
    \47\ Wisc. Gas Co. v. FERC, 770 F.2d 1144, 1156 (1985); see also
Associated Gas Distrib. v. FERC, 824 F.2d 981, at 1018 (D.C. Cir.
1987).
    \48\ Dickenson v. Zurko, 527 U.S. 150, 155 (1999).
---------------------------------------------------------------------------

    37. As discussed throughout this Final Rule, the reforms adopted in
this proceeding are intended to ensure that rates for jurisdictional
services remain both just and reasonable and are not unduly
discriminatory or preferential. In this way, the reforms contained in
this Final Rule build on the work of Order No. 890, in which the
Commission made several reforms to the pro forma OATT, in part because
of a recognition that the mix of generation resources on the system was
changing and that not all generation resources were similarly
situated.\49\ Like the reforms instituted in Order No. 890, the reforms
adopted herein are designed to remedy deficiencies in existing
requirements that can cause the rates, terms, and conditions of
jurisdictional services to become unjust and unreasonable or unduly
discriminatory or preferential.
---------------------------------------------------------------------------

    \49\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 2 (citing
Order No. 890, FERC Stats. & Regs. ] 31,241 at P 5. The Commission
further recognized that intermittent resources, such as wind power,
have a limited ability to control their output, and that this
limitation supports tailoring certain requirements to the special
circumstances presented by this type of resource. Order No. 890,
FERC Stats. & Regs. ] 31,241 at P 663 (requiring that generator
imbalance provisions account for the special circumstances presented
by intermittent generators).
---------------------------------------------------------------------------

    38. The basis for adopting changes to the pro forma OATT and pro
forma LGIA is discussed in the sections below addressing reforms to
transmission scheduling practices and the reporting of meteorological
data. There the Commission concludes that changes to scheduling
practices are necessary in order to ensure that charges for generator
imbalance service under schedule 9 of the pro forma OATT and for
generator regulation service, as relevant, are just and reasonable and
not unduly discriminatory. The Commission also concludes that, without
the reporting requirements adopted herein, the terms of the pro forma
LGIA may impair the ability of public utility transmission providers to
develop and deploy power production forecasting, which in turn can lead
to rates for jurisdictional services that are unjust and unreasonable
or unduly discriminatory.
    39. The Commission concludes that we have the authority to make
these determinations under applicable precedent, including National
Fuel. In that case, the court found that the

Commission had not met the substantial evidence standard when it sought
to extend its Standards of Conduct that regulate natural gas pipelines'
interactions with their marketing affiliates to their interactions with
their non-marketing affiliates. The court noted that it had previously
upheld the Standards of Conduct as applied to marketing affiliates
because the Commission had demonstrated both a theoretical threat,
namely that pipelines could grant undue preferences to their marketing
affiliates, and substantial record evidence that such abuse had
actually occurred.\50\ In considering the Commission's order extending
the Standards to non-marketing affiliates, the court found that the
Commission had cited a theoretical threat of undue preference, but had
not cited a single example of actual abuse by non-marketing affiliates.
It concluded that instead of providing evidence of a real problem with
respect to non-marketing affiliates, the Commission had relied either
on examples of abuse by marketing affiliates, and therefore already
covered by the old Standards, or on comments from the rulemaking that
merely reiterated a theoretical potential for abuse.\51\ The court
remanded the matter and noted that if the Commission chose to proceed
with promulgating the new Standards, it would have to develop a factual
record to support them. If the Commission decided instead to rely
solely on a theoretical threat, it would need to show how this threat
justified the costs that the Standards would create.\52\
---------------------------------------------------------------------------

    \50\ National Fuel, 468 F.3d at 840.
    \51\ Id. at 841.
    \52\ Id. at 844.
---------------------------------------------------------------------------

    40. Our actions in this Final Rule are consistent with the
standards that the court set forth in National Fuel. We conclude that,
in light of the increasing deployment of VERs on the nation's
transmission system, the reforms adopted herein are necessary to
correct operational practices that can limit the cost-effective
integration of VERs into the transmission system consistent with open
access principles. In other words, the problem that the Commission
seeks to resolve represents a ``theoretical threat,'' in the words of
the National Fuel decision, the features of which are discussed
throughout the body of this Final Rule in the context of each of the
reforms adopted herein. This threat is significant enough to justify
the reforms imposed by this Final Rule. It is not one that can be
addressed adequately or efficiently through the adjudication of
individual complaints.\53\ In the terminology of National Fuel, the
remedy we adopt is justified sufficiently by the ``theoretical threat''
identified herein, even without ``record evidence of abuse.'' The
actual experiences of problems cited in the record herein provide
additional support for our action, but are not necessary to justify the
remedy.
---------------------------------------------------------------------------

    \53\ Individual adjudications by their nature focus on discrete
questions of a specific case. Rules setting forth general principles
are necessary to ensure that adequate processes are in place.
---------------------------------------------------------------------------

    41. Citing Enron, Southern and EEI also argue that the Commission
does not have the authority to remedy undue discrimination in
situations where facially neutral operational practices result in a
disparate impact on different market participants. The Commission
disagrees. Enron involved an OATT Filing by a public utility (Entergy)
in which the utility sought to require point-to-point transmission
customers to designate specific sources and sinks for transmission
service. The proposal also set forth what the utility would accept as a
valid source or sink, prohibiting a generator (or generation-only
control area) from being a sink, and prohibiting a load (or load-only
control area) from being a source.\54\ Customers objected to the
proposal, arguing that the provision would not limit Entergy's ability
to reserve capacity and schedule in and out of its control area because
it had load and generation within its control area, but would prohibit
similar transactions from customers operating control areas completely
surrounded by Entergy that sought to set up transactions in and out of
those control areas. The Commission evaluated Entergy's proposal under
the applicable standard of review, i.e., whether the OATT Filing was
consistent with or superior to the Order No. 888 pro forma OATT. The
Commission accepted the proposal, and the United States Court of
Appeals for the District of Columbia Circuit upheld the decision.\55\
---------------------------------------------------------------------------

    \54\ Enron, 296 F.3d at 1151.
    \55\ Id. at 1153-54.
---------------------------------------------------------------------------

    42. We find that commenters' reliance on Enron is misplaced. In
Enron, the Commission reviewed a tariff filing made under section 205
of the FPA to determine if it was consistent with or superior to the
pro forma OATT. The scope of that analysis is not analogous to that of
our inquiry in this proceeding, which is to determine if changes to the
pro forma OATT and pro forma LGIA are necessary to ensure that rates
for jurisdictional services remain just and reasonable and not unduly
discriminatory. In any event, to the extent that Enron may be relevant
to a rulemaking proceeding of general applicability, Southern and EEI
appear to misunderstand the result in Enron. In that case, the court
found that it was neither arbitrary nor capricious for the Commission
to accept a tariff provision forbidding the designation of a generator-
only control area as a sink and a load-only control area as a source as
comparable to the pro forma OATT.\56\ In addition to this holding, the
court indicated that it was sufficient for the Commission to address
comparability of an OATT (the applicable standard in that proceeding)
``on the basis of the terms and conditions offered to customers, not on
the usefulness of those terms and conditions to a particular customer
because of that customer's capacities and needs,'' noting also that the
Commission found that the provision was not discriminatory.\57\
---------------------------------------------------------------------------

    \56\ Id. at 1151-52.
    \57\ Id. at 1151. The court further found that the Commission
adequately addressed charges that the provision would lead to
discriminatory treatment by accepting the utility's commitment to
apply the provision on a nondiscriminatory basis.
---------------------------------------------------------------------------

    43. Enron did not, as Southern and EEI suggest, reject the notion
that facially-neutral, technology- and customer-blind operational
practices could be found to be unduly discriminatory because of the
effects or impacts of those requirements on different customer groups.
Instead, the relevant Enron dicta indicate that the Commission could
sustain a determination that a tariff provision is comparable to the
pro forma OATT where it offers the same terms and conditions to
customers, notwithstanding a difference in how different customers will
use or benefit from those tariff provisions.\58\ However, nothing in
Enron mandates that result.
---------------------------------------------------------------------------

    \58\ Id.
---------------------------------------------------------------------------

    44. Our conclusion that Southern and EEI erred in their
interpretation of Enron is bolstered by other cases included in the
comments of both parties. For example, Southern and EEI cite Alabama
Power for the proposition that, in instances where a single rate is
found to have disparate cost impacts on dissimilar customers, such a
result is only considered unduly discriminatory if the differences
cannot be cost justified.\59\ In Alabama Power, the issue for the court
was whether an application of the same rate to two groups of customers
that were similar in many respects may nevertheless violate statutory
prohibitions against unduly discriminatory rate schemes. That case
involved rate filings by a utility that

applied the same rate to two groups of wholesale service customers. One
group alleged that this single rate represented a misallocation of
costs, resulting in that group paying significantly more (and the other
paying significantly less) than the costs for which its members were
responsible. The court held that notwithstanding the fact that the same
rate applied to both groups of customers, the Commission was obligated
to evaluate whether the different costs imposed by those two groups
rendered the use of a single rate unduly discriminatory.\60\
---------------------------------------------------------------------------

    \59\ Southern (citing Alabama Power, 684 F.2d at 29); EEI
(citing Alabama Power, 684 F.2d 20).
    \60\ Alabama Power, 684 F.2d at 28-29.
---------------------------------------------------------------------------

    45. Southern argues that a finding in the Proposed Rule--that
existing hourly transmission scheduling protocols expose transmission
customers to ``excessive or unduly discriminatory generator imbalance
charges''--may run afoul of Alabama Power because VER customers require
greater amounts of imbalance service and therefore should be required
to pay more in the way of imbalance charges.\61\ Southern and EEI
contend that, because VERs are not similarly situated to dispatchable
generation for scheduling and imbalance purposes, existing scheduling
and imbalance practices cannot be unduly discriminatory toward
VERs.\62\ Similarly, ELCON argues that the Proposed Rule would require
all ratepayers to subsidize the integration of VERs despite not
receiving any benefits, thereby violating cost causation principles.
---------------------------------------------------------------------------

    \61\ Southern (citing Proposed Rule, FERC Stats. & Regs. ]
32,664 at P 37).
    \62\ Both Southern and EEI cite additional authority for this
point, i.e., that in order to demonstrate that it was unduly
discriminated against, a party must show that it is similarly
situated to another party receiving different treatment. See EEI
(citing Ark. Elec. Energy Consumers v. FERC, 290 F.3d 362 (D.C. Cir.
2002) (``a rate is not `unduly' preferential or `unreasonably' ''
discriminatory in violation of the FPA if disparate effect of
transmission or sale of electric energy by the jurisdictional
utility can justify the disparate effect'')); Southern (citing City
of Vernon v. FERC, 845 F.2d 1042, 1045-46 (D.C. Cir. 1988) (``The
Commission's opinion sets forth a two-part test for discriminatory
treatment where different rates or services are offered, requiring a
showing that the unequally treated customers are `similarly
situated,' and that the service sought is the `same service'
actually offered elsewhere.'') & n.2 (``FERC has typically relied on
factors like these in defining a prima facie case of undue
discrimination.''); see, e.g.,Sacramento Mun. Util. Dist. v. FERC,
474 F.3d 797, 802 (D.C. Cir. 2007) (``In order for PG&E's refusal to
negotiate a successor agreement with [Sacramento Municipal Utility
District (SMUD)] to constitute undue discrimination, SMUD must
demonstrate it is similarly situated to Western.'').
---------------------------------------------------------------------------

    46. As with commenters' reliance on Enron, we find that commenters'
reliance on Alabama Power is misplaced. The Commission is not
determining whether a single rate imposed on two groups of customers
may unduly discriminate against one of those groups. Instead, the
Commission is promulgating a generic rule that amends the scheduling
requirements of the pro forma OATT to remedy practices throughout the
industry that may be causing jurisdictional rates to be excessive or
unduly preferential. Accordingly, the task before the Commission is not
comparing the impact of a concrete rate proposal on distinct and
readily identifiable customers or classes. Rather, the Commission is
broadly evaluating whether the pro forma OATT contains the appropriate
set of requirements to ensure that rates for all customers remain just
and reasonable and not unduly discriminatory. As in Order No. 890, the
Commission is acting in part to remedy OATT provisions that may allow
public utility transmission providers to treat some customers in an
unduly discriminatory manner. Such an endeavor necessarily requires the
Commission to take notice of the general developments in the electric
industry in deciding what generic reforms may be needed to ensure that
the pro forma OATT does not unduly discriminate against any one class
of customers.\63\
---------------------------------------------------------------------------

    \63\ See Transmission Access Policy Study Group v. FERC, 225
F.3d 667 (D.C. Cir. 2000) (TAPS) (affirming Order No. 888 rulemaking
based on general findings, rejecting utility arguments that FERC
must have substantial evidence and make specific factual findings);
Wisc. Gas Co. v. FERC, 770 F.2d 1144 (affirming that Commission need
not make individual findings regarding each affected entity but can
rely on a broader record in promulgating rule of general
applicability); Associated Gas Distrib. v. FERC, 824 F.2d 981
(affirming that the Commission is not required to have empirical
data for all the propositions upon which its order depended before
promulgating a rule).
---------------------------------------------------------------------------

    47. In Order No. 890, the Commission recognized that the mix of
generation resources on the system was changing and that not all
generation resources were similarly situated.\64\ In response, the
Commission instituted reforms that recognized the unique nature of
intermittent resources, tailoring certain requirements to the special
circumstances presented by this type of resource.\65\ We again
recognize that VERs, by definition,\66\ are not similarly situated to
conventional, dispatchable generators and that reforms to the pro forma
OATT are necessary to ensure that these resources are treated in a fair
and not unduly discriminatory manner. Simply because VERs are not
similarly situated in all respects to conventional, dispatchable
generators, it does not follow, as Southern and EEI assert, that
existing pro forma OATT provisions that place a disproportionate burden
on VERs are just and reasonable.\67\ The more frequent scheduling
intervals required by this Final Rule will enable VERs, as well as
other generators, to schedule transmission service accurately based on
forecasted energy output. This will mitigate VERs' exposure to
imbalance charges, while at the same time giving public utility
transmission providers a better understanding of expected energy flows
on their systems.
---------------------------------------------------------------------------

    \64\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 5.
    \65\ Id. P 663 (requiring that generator imbalance provisions
account for the special circumstances presented by intermittent
generators).
    \66\ See supra note 1 (defining VER).
    \67\ See Alabama Power, 684 F.2d at 23-24 (``It matters little
that the affected customer groups may be in most respects similarly
situated--that is, that they may require similar types of service at
similar (even if varying) voltage levels. If the costs of providing
service to one group are different from the costs of serving the
other, the two groups are in one important respect quite
dissimilar.'').
---------------------------------------------------------------------------

    48. The Commission does not need to make specific findings with
respect to each affected entity so long as the agency's factual
determinations are reasonable.\68\ As further discussed herein, the
Final Rule amends the pro forma OATT in ways that will limit
uncertainty and provide additional control over scheduling, which
should reduce imbalance charges for all customers. The proposed reforms
will further benefit customers and the market as a whole by providing
increased flexibility and encouraging innovation and participation by
new market participants.\69\ While the Commission commenced this
proceeding as a response to the significantly increasing penetration of
VERs into the nation's generation portfolio, the Commission's purpose
is not to favor VERs over other forms of generation (or demand)
resources. Quite the contrary, a primary goal of this proceeding is to
remove obstacles that can have a discriminatory impact on the ability
of VERs to compete in the marketplace and that can otherwise result in
unjust and unreasonable rates for all market participants.\70\
---------------------------------------------------------------------------

    \68\ TAPS, 225 F.3d at 688 (citing Wisc. Gas Co. v. FERC, 770
F.2d at 1158).
    \69\ Cf. Order No. 679, Promoting Transmission Investment
through Pricing Reform, Order No. 679, FERC Stats. & Regs. ] 31,222,
at PP 131, 176, 224, order on reh'g, Order No. 679-A, FERC Stats. &
Regs. ] 31,236, at P 77 (2006), order on reh'g, Order No. 679-B, 119
FERC ] 61,062 (2007). The Commission does not authorize these
measures to provide a unilateral benefit to transmission owners but
rather to encourage the development of needed transmission, which
has broader benefits to the market and consumers.
    \70\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 23.
---------------------------------------------------------------------------

    49. Finally, in response to Southern, the Commission notes that it
is not

asserting jurisdiction over the practice of power production
forecasting in this Final Rule. Rather, the Commission is adopting
changes to the pro forma LGIA to impose reporting requirements on
interconnection customers whose generating facilities are VERs. As
discussed in further detail later in this Final Rule, power production
forecasting can be used by public utility transmission providers to
significantly reduce operating costs associated with the integration of
VERs interconnected to their systems.\71\ However, the ability of
public utility transmission providers to engage in power production
forecasting may be limited without data from interconnected VERs. In
order to facilitate a public utility transmission provider's use of
power production forecasting to reduce its operating costs, the
Commission is amending the requirements of the pro forma LGIA to impose
a data reporting requirement as a condition of interconnection service
for interconnection customers whose generating facilities are VERs.
---------------------------------------------------------------------------

    \71\ See infra Sec.  IV.B.1 (Data Requirements).
---------------------------------------------------------------------------

    50. The question then is whether the Commission has jurisdiction to
condition the grant of interconnection service on the reporting of
meteorological and outage data by interconnection customers whose
generating facilities are VERs as a practice affecting rates subject to
the Commission's jurisdiction under the FPA.\72\ As the Commission
explained in Order No. 2003, interconnection service is a component of
open access transmission service, subject to the Commission's
regulation under sections 205 and 206 of the FPA.\73\ The reporting of
meteorological and outage data by VER customers taking jurisdictional
interconnection service has a direct affect on the ability of the
public utility transmission provider to efficiently manage the VER
integration through the development and deployment of power production
forecasting. Failure to require the reporting of this data could limit
the public utility transmission provider's ability to develop and
deploy power production forecasts and, in turn, its attempts to
efficiently commit or de-commit resources providing regulation
reserves, potentially resulting in rates for reserve-related services
that are unjust and unreasonable or unduly discriminatory. It is
therefore reasonable for the Commission to conclude that it is within
our jurisdiction to implement the data reporting requirements of this
Final Rule as a condition of interconnection service.
---------------------------------------------------------------------------

    \72\ See Cal. Indep. Sys. Oper. v. FERC, 372 F.3d 395 (D.C. Cir.
2004).
    \73\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at 12.
---------------------------------------------------------------------------

IV. Proposed Reforms

A. Intra-Hour Scheduling

    51. The first of the two reforms adopted in this Final Rule relates
to the intervals at which transmission customers may submit
transmission schedules under the pro forma OATT. As discussed below,
the Commission amends the pro forma OATT to provide all transmission
customers the option of using more frequent transmission scheduling
intervals within each operating hour, at 15-minute intervals. The
Commission concludes this change to existing operational practices is
necessary in order to ensure that charges for generator imbalance
service under Schedule 9 of the pro forma OATT and for generator
regulation service, as relevant, are just and reasonable and not unduly
discriminatory.
1. Intra-Hour Scheduling Requirement
a. Commission Proposal
    52. In the Proposed Rule, the Commission preliminarily found that
hourly transmission scheduling protocols are no longer just and
reasonable and may be unduly discriminatory as the default scheduling
time periods required by the pro forma OATT. Specifically, the
Commission preliminarily found that existing hourly transmission
scheduling protocols expose transmission customers to excessive or
unduly discriminatory generator imbalance charges and are insufficient
to provide system operators with the flexibility to manage their system
effectively and efficiently. Therefore, the Commission proposed to
amend sections 13.8 and 14.6 of the pro forma OATT to provide
transmission customers the option to schedule transmission service on
an intra-hour basis, at intervals of 15 minutes. The Commission noted
that its proposed reform would allow for intra-hour scheduling
adjustments and that it did not propose changes to the hourly
transmission service reservation provided in the OATT.\74\
---------------------------------------------------------------------------

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

    53. The Commission acknowledged in the Proposed Rule that a number
of public utility transmission providers already have begun
implementing intra-hour scheduling practices. The Commission stated
that, while these individual reforms are important steps toward the
efficient integration of VERs, it believed that it also is important to
establish 15-minute scheduling periods as the default scheduling
process. At the same time, the Commission acknowledged arguments that
regional differences should be respected when developing an
implementation process and that any Commission action should not
negatively affect ongoing industry efforts. In that regard, the
Commission sought comment on the best approach for implementing the
proposed intra-hour scheduling reforms. The Commission recognized that
an optimal implementation approach should support ongoing industry
efforts and may consider regional differences, such as the amount of
VERs present in that region. In proposing implementation approaches,
the Commission encouraged commenters to consider any impacts on
transmission customers scheduling across multiple systems and whether
these impacts diminish the benefits of implementing intra-hour
scheduling.\75\
---------------------------------------------------------------------------

    \75\ Id. PP 42-43.
---------------------------------------------------------------------------

    54. To understand more fully the modifications that this proposed
reform may require, the Commission sought comment on the specific
hardware, software, and personnel changes that are necessary to
implement intra-hour scheduling. The Commission further inquired as to
whether there would be any additional impacts on relatively small
public utility transmission providers, and how to best facilitate this
reform for small public utility transmission providers.
b. Comments
i. Obligation to Offer Intra-Hour Scheduling
    55. A number of commenters support the Commission's proposal to
require public utility transmission providers to offer intra-hour
scheduling,\76\ although some seek clarifications or modifications of
the proposal. Additionally, commenters disagree as to the appropriate
period of time for submitting intra-hour schedules. These commenters
generally agree that intra-hour scheduling would enable transmission
customers to align transmission schedules with actual generation output
more effectively, reduce the need for transmission providers to carry
expensive operating

reserves, and provide for greater system flexibility by utilizing
available resources in a more efficient manner.
---------------------------------------------------------------------------

    \76\ E.g., A123; Alstom Grid; ACSF; Argonne National Lab; BP
Energy; California ISO; CESA; CMUA; CEERT; Center for Rural Affairs;
Clean Line; CGC; Defenders of Wildlife; Environmental Defense Fund;
EPSA; Exelon; First Wind; FriiPwr; Independent Power Producers
Coalition--West; Independent Energy Producers; ITC Companies;
NextEra; NaturEner; Organization of Midwest ISO States; Oregon and
New Mexico PUC; Public Interest Organizations; Powerex; SWEA; Tacoma
Power; Tres Amigas; TVA; Vestas; Viridity Energy; Vote Solar;
Western Grid; Xcel.
---------------------------------------------------------------------------

    56. For example, EPSA states that the option of 15-minute
scheduling would expand the availability of flexible generation
resources and demand response resources to provide additional liquidity
and consistency in the market. Exelon argues that implementing intra-
hour scheduling will reduce supply-side uncertainty, which should allow
resources to be more optimally selected and allocated than otherwise
would be the case. Powerex contends that shorter scheduling intervals
would allow the use of more accurate forecasts that are closer to the
operating time-frame. Joined by CEERT and others, Powerex argues that
intra-hour scheduling would increase transmission system flexibility
and efficiency, providing grid operators with more options for
scheduling resources during each hour and decreasing the need for (and
costs of) ancillary services needed for reliable integration of
VERs.\77\ The Center for Rural Affairs asserts that making intra-hour
scheduling available is essential for public utility transmission
providers and balancing authorities seeking to provide system balance
with increasing generation from VERs.
---------------------------------------------------------------------------

    \77\ E.g., CEERT; Powerex; Public Interest Organizations;
Vestas.
---------------------------------------------------------------------------

    57. While acknowledging that some stakeholders in this proceeding
oppose the mandatory nature of the Commission's proposal, disagree
about scheduling costs, and question the reliability impacts of the
proposed reforms, Public Interest Organizations state that almost all
stakeholders have acknowledged that intra-hour scheduling does improve
scheduling accuracy and decrease the need for energy imbalance
services. Public Interest Organizations, joined by Environmental
Defense Fund and Argonne National Lab, contend that intra-hour
scheduling, as compared to hourly scheduling protocols, allows for a
more accurate prediction of the variable generation that can be
delivered within the market interval, reducing the need to procure
expensive regulation or energy imbalance services.\78\ NaturEner
agrees, arguing that shorter scheduling intervals would allow for more
frequent generation adjustments, thus, decreasing the negative impacts
on both the transmission system and the grid from frequent generation
disruptions. Iberdrola similarly contends that moving toward smaller
intra-hour scheduling intervals will provide incentives for more
complete and efficient scheduling practices and eliminate other
outdated and discriminatory operating practices.
---------------------------------------------------------------------------

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

    58. California ISO states that continuing to require resources to
match hourly transmission schedules would perpetuate inefficient and
burdensome operational requirements. Tres Amigas contends that current
scheduling practices have been associated with underutilized
transmission assets and sub-optimal operating practices resulting in
inefficient curtailment of generation. BP Energy asserts that 15-minute
scheduling intervals will increase the ability of a transmission
customer scheduling energy from a VER to manage the scheduled input
and, therefore, its imbalance costs. Vestas notes that all generators,
regardless of fuel type, will be able to track their schedules more
closely with actual levels of production as a result of intra-hour
scheduling. Vestas explains that, if a large fossil-fueled resource
suffers an outage or derate within an hour, the ability to change its
schedule earlier than the next clock hour can provide significant
benefits to both the generator and the transmission system operator.
Clean Line contends that intra-hour scheduling is likely to have
benefits independent of variable generation integration, stating that
sub-hourly variations in load could be managed in a more cost-effective
manner. Also, A123 contends that shorter scheduling intervals will help
OATT markets incorporate the benefits of high-ramp, limited energy
resources like storage.\79\
---------------------------------------------------------------------------

    \79\ A ramp rate is the rate, expressed in megawatts per minute,
that a resources changes its output. See NERC Glossary of Terms,
available online at http://www.nerc.com/files/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------

    59. However, other commenters oppose mandatory intra-hour
scheduling, arguing generally that current scheduling practices are
neither preferential nor unduly discriminatory.\80\ For example, ELCON
states that the Commission's proposals are costly measures that would
apply preferentially to just one class of generation--VERs--in order to
address discrimination that does not actually exist. Some commenters
argue that further study of the need for intra-hour scheduling should
be undertaken prior to mandating the practice. Several of these
commenters assert that the Commission should not require the
implementation of 15-minute intra-hour scheduling until certain impacts
are better understood.\81\ LADWP submits that intra-hour scheduling
should not be implemented until it has been fully vetted and researched
to assess operational capabilities and coordination.
---------------------------------------------------------------------------

    \80\ E.g., ELCON; Midwest ISO; NV Energy; Southern.
    \81\ E.g., California PUC; LADWP; NorthWestern; NV Energy;
Pacific Gas & Electric.
---------------------------------------------------------------------------

    60. Some commenters argue that the Commission's proposed reform may
not lead to a reduction in aggregate reserve costs. These commenters
contend that the implementation of intra-hour scheduling does not
negate the inherent variability of VERs and, therefore, the cost of
providing balancing services is merely shifted, rather than mitigated,
by intra-hour scheduling.\82\ For example, Avista explains that, while
the host balancing authority will provide a reduced amount of balancing
reserves within each scheduling period, a significant portion of this
variability is being covered by the sink balancing authority or the
load serving entity (LSE). Avista contends the sink balancing authority
or LSE will incur increased balancing costs to follow the fluctuating
VER schedule against a relatively more constant load, thereby shifting
the cost of managing that variability as opposed to creating
substantial cost savings through intra-hour scheduling. If the host
balancing authority area and the sink balancing authority area are the
same, Avista argues that no cost savings or reduction in reserves is
accomplished by the proposed scheduling reforms. Iberdrola argues that
implementing intra-hour scheduling absent a market for dispatchable
resources to manage variability could potentially be more harmful than
helpful to VER integration. Duke argues that, due to the inherent
variability of VERs, more regulating reserves will be needed regardless
of the scheduling interval. While operating experience may diminish the
need for regulating reserves over time, Duke contends that the level of
regulating reserves will ultimately be maintained at a higher level
than required today. M-S-R Public Power Agency encourages the
Commission to consider the effectiveness of reducing overall
intermittency management obligations further before implementing an
intra-hour scheduling reform.
---------------------------------------------------------------------------

    \82\ E.g., Avista; Bonneville Power; M-S-R Public Power Agency;
Xcel.
---------------------------------------------------------------------------

    61. With regard to the appropriate time interval for intra-hour
scheduling, a number of commenters support the Commission's proposal to
require public utility transmission providers to offer intra-hour
scheduling at 15-minute intervals.\83\ Many of these commenters

agree that a scheduling interval of 15-minutes or shorter provides a
number of benefits such as lowering the costs related to integrating
VERs into the market and operational benefits. Argonne National Lab
states that requiring transmission providers to schedule resources with
a frequency of at least every 15 minutes would provide benefits to all
supply and demand resources in the power system, not only VERs. Several
commenters argue that scheduling in 15-minute intervals would reduce
imbalance charges through more accurate schedules.\84\ EPSA notes that
the proposed 15-minute scheduling interval is consistent with NERC
recommendations for achieving greater flexibility while meeting
relevant reliability requirements.\85\ Exelon asserts that 15-minute
scheduling is an industry best practice and that the Commission should
set a deadline by which all transmission providers must conform.
---------------------------------------------------------------------------

    \83\ E.g., A123; Alstom Grid; ACSF; Argonne National Lab; BP
Companies; CESA; CEERT; Center for Rural Affairs; Clean Line; CGC;
Defenders of Wildlife; Environmental Defense Fund; EPSA; Exelon;
First Wind; Independent Energy Producers; ITC Companies; NaturEner;
Organization of Midwest ISO States; Oregon & New Mexico PUC;
Powerex; Public Interest Organizations; SWEA; Tres Amigas; Viridity
Energy; Vote Solar; Western Grid; Xcel.
    \84\ E.g., BP Energy; CEERT; CGC; Defenders of Wildlife; Duke;
NextEra; Public Interest Organizations; SEIA; Vestas; Xcel.
    \85\ EPSA (citing NERC April 12, 2010 Response to NOI at 17-18).
---------------------------------------------------------------------------

    62. Vestas acknowledges that a shortened scheduling interval must
strike a balance between the benefits of increased certainty and
reduced variability resulting from customers' ability to more closely
match their schedules with their anticipated output and any increased
complexity and technical issues that could result if the scheduling
interval is too short. Vestas contends that a 15-minute scheduling
window provides a reasonable compromise between the current hour and
the even shorter 5-minute intervals utilized in certain RTO markets.
Oregon & New Mexico PUC agree that as more wind and solar generation
are integrated into the system, shorter intra-hour intervals will
generate greater cost savings than longer intervals. Oregon & New
Mexico PUC urge the Commission to adopt a minimum standard for
transmission scheduling at 15-minute intervals to focus industry
efforts on implementing a consistent standard rather than debating the
appropriate interval.
    63. Some commenters are concerned that the proposed 15-minute
scheduling interval is too long.\86\ While supportive of 15-minute
scheduling as an interim step, several commenters recommend that the
Commission require public utility transmission providers to move to
shorter scheduling intervals.\87\ RenewElec asserts that 15-minute
scheduling may not be sufficient for the integration of large amounts
of VERs. As an option for increasing flexibility without decreasing the
15-minute scheduling period, SEIA asks the Commission to clarify that
generators may submit 15-minute schedules with different output levels
at the beginning and end of the 15-minute period to reflect anticipated
ramps to manage the variations in diurnal ramping of solar resources.
Vote Solar echoes the concerns of SEIA with regard to solar diurnal
ramping and argues for scheduling intervals more granular than 15-
minutes to accommodate wide-area balancing. Vote Solar recommends that
the Commission additionally require a 5-minute intertie scheduling
interval. However, EEI cautions that if the Commission decides to move
forward with the rule as proposed, the scheduling interval should be no
less than 15 minutes as it may undermine the reliable operation of the
system.
---------------------------------------------------------------------------

    \86\ E.g., Environmental Defense Fund; FriiPower; Independent
Power Producers Coalition-West; RenewElec; SEIA; Vestas.
    \87\ E.g., Environmental Defense Fund; Independent Power
Producers Coalition-West; RenewElec.
---------------------------------------------------------------------------

    64. Other commenters argue that the proposed 15-minute scheduling
interval is too short.\88\ Several commenters recommend an initial 30-
minute intra-hour scheduling interval to coincide with current regional
initiatives or as a general first step.\89\ Some commenters argue that
the Commission should use the output of ongoing regional initiatives to
determine whether a 15-minute scheduling interval is necessary, or
whether another mechanism is the desired method to reduce VER
integration costs.\90\ EEI states that, if there is no demand for
intra-hour scheduling, investments to implement 15-minute scheduling
would be unnecessary. NorthWestern expresses uncertainty as to whether
15-minute scheduling would provide benefits greater than those achieved
through 30-minute scheduling. Southern California Edison suggests that
a 30-minute scheduling interval is sufficient as it can capture
forecast error reductions, align with the commitment capabilities of
most integrating resources, and reduce the need for additional
administrative overhead. Iberdrola recommends that the Commission allow
public utility transmission providers to provide intra-hour schedules
at 30-minute intervals as an interim step to participation in an energy
imbalance market.
---------------------------------------------------------------------------

    \88\ E.g., LADWP; Montana PSC; NV Energy; Puget.
    \89\ E.g., Bonneville Power; California ISO; California PUC;
CMUA; Montana PSC; NorthWestern; NV Energy; Snohomish County PUD;
Southern California Edison; WUTC.
    \90\ E.g., Bonneville Power; California PUC; CMUA; FirstEnergy;
NorthWestern; Snohomish County PUD; Southern California Edison.
---------------------------------------------------------------------------

    65. Some commenters contend that a 15-minute scheduling interval
does not support the standard 20-minute generator/scheduling ramp rate
in the West.\91\ Tacoma Power explains that continuing to use 20-minute
ramps would create interface problems with the receipt of schedules on
a 15-minute interval. Bonneville Power similarly argues that scheduling
on a 15-minute interval would result in almost continuous ramping in a
way that 30-minute scheduling does not, and that the resulting
reduction in dynamic transfer capability could preclude implementation
of other options for reducing VER integration costs. WestConnect
asserts that this may result in a disparity in the accurate scheduling
of VERs and the system operator's ability to efficiently integrate VERs
under restricted ramping intervals.
---------------------------------------------------------------------------

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

    66. Bonneville Power and Xcel request clarification that ``intra-
hour scheduling adjustments'' include both adjustments to existing
schedules and the submission of new schedules.\92\ MidAmerican requests
clarification as to whether intra-hour scheduling is intended to be
available only within the current hour or also in future hours.
---------------------------------------------------------------------------

    \92\ Bonneville Power; Xcel.
---------------------------------------------------------------------------

ii. Consistency in Scheduling Requirements
    67. Commenters differ regarding whether the Commission should adopt
a consistent intra-hour scheduling requirement for all transmission
providers under the pro forma OATT. If the Commission decides to move
forward with its proposal, EEI recommends that the Commission require a
uniform, consistent scheduling interval throughout each
interconnection. EEI contends that this will allow for the development
of uniform and consistent intervals in reliability standards and
business practices and also promote accuracy of results. A number of
other commenters agree that consistent scheduling intervals are needed
in order for intra-hour scheduling to occur across balancing authority
areas.\93\ For

example, NorthWestern and Southern contend that, unless all public
utility transmission providers within an interconnection are required
to comply with the same intra-hour scheduling interval, intra-hour
scheduling may erode a utility's ability to maintain reliability.
---------------------------------------------------------------------------

    \93\ E.g., Argonne National Lab; EEI; Iberdrola; Independent
Power Producers Coalition-West; NaturEner; NorthWestern; NRECA;
Oregon & New Mexico PUC; Public Interest Organizations; Puget;
Southern California Edison; Southern; and Tres Amigas.
---------------------------------------------------------------------------

    68. Public Interest Organizations agree that there is a need to
apply consistent scheduling obligations across the country in order to
avoid undue discrimination against VERs and argue that the benefits of
15-minute intra-hour scheduling will apply throughout the system, not
just to VERs. If the Commission decides to allow for a public utility
transmission provider to propose variations to 15-minute scheduling,
Public Interest Organizations suggest that the entity be required to
demonstrate why a variation is necessary and show that the proposed
alternative will be equally effective or superior to the Commission's
proposal. NextEra points out that the arguments favoring regional
variations in scheduling requirements ignore the fact that many regions
have no overall regional body or authority with sufficient ability to
ensure consistency in resolving issues regarding VER integration.
NextEra submits that the Commission has ultimate responsibility to
ensure that market rules are just and reasonable, and that the
Commission cannot delegate its responsibility to states, regions, or
public utilities. Tres Amigas requests that the Commission clarify that
intra-hour scheduling will apply to all generation scheduled on the
bulk transmission system; inter- and intra-balancing authority
transactions, and point-to-point, network, or native load service. Tres
Amigas states that inconsistent transmission scheduling periods will
lead to inefficient and/or discriminatory use of the transmission
system.
    69. Many commenters contend that the Commission should afford
public utility transmission providers the flexibility to determine how
best to implement intra-hour scheduling in their region. These
commenters ask the Commission to acknowledge that region-specific
scheduling practices may be appropriate in light of system
circumstances and market designs.\94\ Several of these commenters note
that there are regional efforts and pilot programs underway that are
aimed at efficiently managing the integration of VERs and providing an
opportunity for intra-hour scheduling.\95\ These commenters generally
contend that the Commission should support and not undermine such
regional initiatives. Examples of regional initiatives identified by
commenters include the Joint Initiative,\96\ the WECC Efficient
Dispatch Toolkit,\97\ and a pilot between Bonneville Power and the
California ISO to evaluate the use of intra-hour scheduling on the
California-Oregon Intertie.\98\ Several commenters suggest that the
Commission should conduct technical conferences to investigate the
relative merits of these and alternative approaches prior to imposing a
uniform national mandate.\99\
---------------------------------------------------------------------------

    \94\ E.g., Avista; Bonneville Power; California ISO; CMUA;
California PUC; Detroit Edison; Dominion; EEI; FirstEnergy; Grant
PUD; Idaho Power; Independent Power Producers Coalition-West; ISO/
RTO Council; Midwest ISO; Montana PSC; National Grid; NorthWestern;
NRECA; New York ISO; NV Energy; PJM; PNW Parties; Public Power
Council; Puget; SMUD; Southern; Tacoma Power; WUTC; WestConnect.
    \95\ E.g., Avista; Bonneville Power; Business Council;
California ISO; California PUC; CESA; CMUA; EEI; Idaho Power; Joint
Initiative; Montana PSC; National Grid; NorthWestern; NV Energy; PNW
Parties; Puget; SMUD; WestConnect.
    \96\ The Joint Initiative is a consensual, collaborative effort
within the Western Interconnection to develop high-value and cost-
effective regional products, identified through a stakeholder
process, for implementation by interested parties. It is jointly
sponsored by Columbia Grid, Northern Tier Transmission Group, and
WestConnect. Joint Initiative at 1-3. Step one of the Products and
Services Strike Team intra-hour scheduling initiative began in July
2011 with the scheduling of transmission in half hour increments.
Step two includes broader application of intra-hour scheduling and
scheduling in finer increments (15 or 20 minutes) only after
evaluation that this step is necessary.
    \97\ The WECC Efficient Dispatch Toolkit contains: (1) An
enhanced curtailment calculator that will aid in managing flows
across constrained paths; and (2) an energy imbalance market that
will efficiently dispatch resources in response to imbalance.
    \98\ This pilot program is intended to facilitate the export of
wind resources located in Bonneville Power's Balancing Authority
into the California ISO. The pilot will use dynamic e-tagging and
communication to facilitate intra-hour schedule changes, beginning
with a 30-minute scheduling interval.
    \99\ E.g., California ISO; Grays Harbor PUD; Pacific Gas &
Electric; SMUD; Snohomish County PUD.
---------------------------------------------------------------------------

    70. Some commenters express concern that a Commission mandate may
detrimentally affect current regional efforts by diverting resources
from or discouraging participation in voluntary regional initiatives by
both jurisdictional and non-jurisdictional entities.\100\ Bonneville
Power and CMUA suggest that ongoing initiatives may provide the
Commission with real-world data and alternative options to reach the
Commission's stated goals. In order to support ongoing regional
initiatives, Pacific Gas & Electric recommends that the Commission not
implement 15-minute scheduling until regional initiatives have been
given a reasonable amount of time to come to an end. Grant PUD argues
that 20-30 minute scheduling intervals appear to be sufficient for the
Northwest region of the country and that the Commission should allow
this to be considered a ``regional practice.'' \101\ In addition, NRECA
argues that the Commission should afford public utility transmission
providers an opportunity to demonstrate that existing practices or
practices under development are or will be consistent with or superior
to the Commission's proposed reforms.
---------------------------------------------------------------------------

    \100\ E.g., Avista; Bonneville Power; California PUC; EEI; Idaho
Power; National Grid; NorthWestern; NRECA; NV Energy; PNW Parties.
    \101\ Grant PUD at 4.
---------------------------------------------------------------------------

    71. Some commenters stress the need for regional flexibility
because, in their view, intra-hour scheduling may not be the right
decision for everyone.\102\ For example, LADWP asserts that the
Proposed Rule is ill-timed, and that intra-hour scheduling may not be
necessary in regions where the existing generation portfolio provides
sufficient flexibility to integrate a fixed percentage of VER
penetration reliably. Southwestern explains that, as a federal agency
operating under a Congressional statutory mandate, the Administration
may not be able to implement intra-hour scheduling as this may impact
the purposes of the Corps projects such as flood control, hydropower,
navigation, fish and wildlife, and recreation. If the Commission adopts
the Proposed Rule, NRECA urges the Commission to permit public utility
transmission providers to seek a waiver from implementing intra-hour
scheduling until the entity receives a request to schedule intra-hour.
---------------------------------------------------------------------------

    \102\ E.g., ISO/RTO Council; NorthWestern; Pacific Gas &
Electric; PNW Parties; Public Power Council; Puget.
---------------------------------------------------------------------------

    72. A number of commenters question the applicability of the
proposed intra-hour scheduling requirements in regions with RTOs/ISOs,
arguing that these markets already provide for system flexibility that
is consistent with or superior to the intra-hour scheduling protocol
proposed by the Commission.\103\ Business Council suggests that the
Commission should focus its attention on areas where rapid spot energy
and ancillary service markets do not exist, particularly non-RTO/ISO
areas that are experiencing significant renewable energy penetration.
ISO/RTO Council asks the Commission to recognize that different regions
currently provide varying levels of flexibility to VERs through
different

systems and market mechanisms, suggesting that the Commission craft the
Final Rule in a manner that allows transmission providers to work with
their stakeholders to develop solutions that work for their region.
FirstEnergy asserts that each RTO and ISO, through its stakeholder
process, should be given the opportunity to evaluate the potential need
for, and benefits and costs associated with, intra-hour scheduling.
Sunflower and Mid-Kansas similarly argue that the Final Rule should
recognize the differences between organized markets and not group them
with non-RTO public utility transmission providers. Environmental
Defense Fund asserts that, because some RTOs and/or balancing
authorities have begun to implement regional scheduling reforms, the
Commission should avoid imposing duplicative requirements or
obstructing such efforts.
---------------------------------------------------------------------------

    \103\ E.g., AWEA; California ISO; California PUC; Detroit
Edison; Iberdrola; ISO New England; Massachusetts DPU; Midwest ISO;
PJM; Public Interest Organizations; RENEW; Sunflower and Mid-Kansas;
Western Farmers.
---------------------------------------------------------------------------

    73. Some commenters suggest that the Commission clarify that its
proposed intra-hour scheduling reforms apply only to RTOs and ISOs in
the context of transactions between balancing authorities.\104\
However, National Grid cautions the Commission against overly-
prescriptive requirements for scheduling between regions and asks for
clarification that public utility transmission providers are permitted
to pursue other scheduling improvements for cross border transactions
and inter-tie scheduling. National Grid notes that New York ISO and ISO
New England are already working on solutions to improve interregional
interchange scheduling. ISO/RTO Council states that accelerated
scheduling changes may negatively affect RTO and ISO interchanges with
non-market areas, as those smaller areas may be unable to keep up with
an RTO or ISO scheduling within the hour.
---------------------------------------------------------------------------

    \104\ E.g., AWEA; Iberdrola; Public Interest Organizations; and
RENEW.
---------------------------------------------------------------------------

    74. Many commenters express concern regarding the potential for
seams issues, particularly with transmission providers that are not
subject to the Commission's ratemaking jurisdiction under sections 205
and 206 of the FPA.\105\ Some commenters argue that, for a generator to
submit a 15-minute schedule, all balancing authorities involved in the
transmission chain must approve the tag or it will be rejected.\106\
While the source balancing authority may approve the schedule, PNW
Parties explain that the schedule may be denied in the adjacent
balancing area if the same intra-hour scheduling procedures are not
used, irrespective of the jurisdictional status of the transmission
providers involved. Xcel suggests that, in areas where the balancing
authority and transmission provider are separate entities, explicit
guidance may be needed in order for a balancing authority to accept
intra-hour schedules from a transmission provider. Xcel recommends that
the Commission place responsibility on the balancing authority to
approve intra-hour scheduling changes made in accordance with an
approved tariff.
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    \105\ E.g., Avista; California ISO; Duke; EEI; Idaho Power;
MidAmerican; NorthWestern; NV Energy; PNW Parties; Puget; Southern
California Edison; Southern; Tres Amigas; WUTC.
    \106\ E.g., PNW Parties; Puget; WUTC.
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    75. Additionally, these commenters question how beneficial intra-
hour scheduling will be in the absence of consistent and compatible
scheduling intervals among jurisdictional and non-jurisdictional
entities.\107\ Puget states that, while it has offered intra-hour
scheduling since December 2009, its customers have scheduled few
transactions due to the lack of conforming scheduling practices in
neighboring non-jurisdictional utilities. If transmission customers are
unable to schedule across seams at 15-minute intervals, Puget argues
that jurisdictional utilities will receive little benefit from the
required software, personnel and accounting changes needed to
facilitate 15-minute scheduling. Idaho Power submits that seams issues
created by different intervals in adjacent systems may ultimately lead
to an increase in the costs of VER integration. WUTC asserts that for
jurisdictional entities to implement intra-hour scheduling unilaterally
would be economically unproductive and may disrupt reliability
functions. Idaho Power and EEI similarly contend that seams issues may
affect reliability.
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    \107\ E.g., Avista; California ISO; Duke; EEI; Idaho Power;
NorthWestern; NV Energy; PNW Parties; Puget; Southern California
Edison; Southern; Tres Amigas; WUTC.
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    76. EEI suggests that the Commission not require public utility
transmission providers to provide intra-hour scheduling prior to an
evaluation of the impacts on coordination between and among
jurisdictional and non-jurisdictional entities. California ISO contends
the parties in the West should continue with coordinated efforts to
find reasonable solutions that can be implemented without placing an
undue burden on neighboring parties. California PUC recommends that the
Commission allow sufficient flexibility for public utility transmission
providers to determine the most efficient way to support intra-hour
scheduling across interties.
    77. Snohomish County PUD and Grays Harbor PUD request that the
Commission evaluate whether existing supply arrangements with
Bonneville Power, referred to as ``slice'' contracts, allow for intra-
hour scheduling before adopting the proposed requirements. Snohomish
County PUD explains that these contracts allow customers to pay a fixed
percentage of Bonneville Power's costs and, in turn, receive an equal
percentage of output, thereby taking advantage of the flexibility of
the federal system. However, Snohomish County PUD and Grays Harbor PUD
state that these ``slice'' contracts limit customers to hourly
scheduling. Snohomish County PUD is concerned that it and other
similarly situated transmission providers may be unable to implement
15-minute scheduling. Snohomish County PUD contends that, as a result,
it and others may have to acquire additional reserves in order to
balance wind resources, in effect paying twice for the same capacity
and scheduling flexibility. Snohomish County PUD asserts that this
issue has already arisen in Bonneville Power's ongoing efforts to
develop intra-hour scheduling at 30-minute intervals.
iii. Cost to Implement Intra-Hour Scheduling
    78. A number of parties address the potential costs of implementing
the Commission's proposed intra-hour scheduling requirement. Exelon
states that there likely will be some development and ongoing
administrative costs, such as modifying Open Access Same-Time
Information System (OASIS) and interchange ramp software and additional
staff to evaluate and confirm more frequent scheduling changes, but
does not expect that such costs would be excessive. Tres Amigas
contends that the incremental costs of providing intra-hour scheduling
will be very modest. NaturEner argues that many transmission providers
could implement intra-hour scheduling with existing staff and equipment
but that, even if that is not the case, entities should be incentivized
or required to automate or otherwise update their system as it would
expedite the scheduling and transmission approval system. Independent
Power Producers Coalition-West contends that increased automation and
staffing would enhance the ability of a balancing authority to schedule
at shorter intervals and achieve further integration of VERs.
    79. Other commenters state that the cost of implementing intra-hour

scheduling may be significant.\108\ EEI and PNW Parties assert that
intra-hour scheduling will affect many activities and systems, causing
transmission providers in some regions to institute hardware, software,
and personnel changes. For example, EEI and PNW Parties contend that
changes will be required to numerous computer systems, such as energy
management systems, scheduling applications, and automated checkout
systems such as the WECC Interchange Tool, and also that certain
practices not currently automated will have to be automated. EEI and
PNW Parties note that staff would need to be trained on these new tools
and additional staff would be required to process the expanded
scheduling information being received. NRECA contends that the costs
will be driven largely by software and personnel changes, rather than
hardware investments, but that it is difficult to estimate with
precision what software changes would be needed without knowing what
measures NAESB will adopt in order to standardize the new scheduling
regime.
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    \108\ E.g., Avista; Bonneville Power; EEI; Grant PUD;
MidAmerican; NRECA; NorthWestern; PNW Parties; Puget; Snohomish PUD;
Southern California Edison; Southwestern; Tacoma Power; TVA.
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    80. NextEra explains that several steps will need to be taken in
order to implement 15-minute scheduling but contends that the cost
impacts are uncertain. NextEra provides that actions to implement
intra-hour scheduling include potential modifications to both internal
and external software packages. According to NextEra, these software
programs, providing functions such as eTagging, accounting, and
billing, will need to be harmonized across vendors. Additionally,
NextEra contends that it is unclear whether existing systems would need
to be replaced or modified, or whether functions currently being
performed manually would need to be automated.
    81. Some transmission providers estimate the level of investment
and staffing changes that would be required to implement 15-minute
scheduling on their system, although most discuss such estimates in the
context of a broader range of activities that they believe may be
intended or implicated by the implementation of 15-minute
scheduling.\109\ For example, Avista states that it would need to hire
and train around-the-clock personnel at an estimated cost of $1.2
million per year to implement ``an approach that will allow for
schedule adjustments and imbalance settlements in 15 minute periods.''
\110\ MidAmerican estimates approximately $1.0 million in staff costs
to implement ``similar intervals for balancing activities and
interchange'' and, to the extent energy management and accounting
systems must be changed, up to $2.0-2.3 million in infrastructure
upgrades.\111\ Bonneville Power also contends that it would need an
additional 24x7 position, staffed by six full-time employees, to manage
what it characterizes as the risks created by 15-minute scheduling,
including the redesign of imbalance service and increased use of
special protection schemes.
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    \109\ E.g., Avista; Bonneville Power; Grant PUD; MidAmerican;
NorthWestern; PNW Parties; Puget; Snohomish County PUD;
Southwestern; Tacoma Power; TVA.
    \110\ Avista at 12, 14 (emphasis in original).
    \111\ MidAmerican at 14.
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    82. NRECA notes that the relative cost impact of implementing
intra-hour scheduling will depend on a number of factors, such as the
size of the system and how widely intra-hour scheduling is utilized.
Although agreeing that the costs may be significant, NRECA states that
costs are not expected to be extraordinary and can be mitigated through
proper design and implementation. NRECA estimates implementation costs
under a range of scenarios. Assuming hourly schedules at a 15-minute
interval used only by VERs, NRECA anticipates the need for software
modifications in the range of $50,000 per company, but notes that some
of its members have incurred expenses in the range of $250,000 annually
for software licensing and maintenance related to scheduling and energy
accounting software upgrades. If hourly schedules at a 15-minute
interval are widely used by transmission customers, NRECA estimates a
minimum of one additional 24x7 shift, resulting in approximately $1.0
million of staffing costs, and potentially two 24x7 positions depending
on the size of the transmission provider. Finally, if hourly schedules
at a 15-minute interval are settled on a 15-minute basis, NRECA
estimates an additional $250,000 to $300,000 for additional ``back
room'' staff to settle 15-minute schedules, interchange and deviation
accounts.
    83. Bonneville Power contends that many of the short-term costs
associated with 15-minute scheduling would not be incurred to implement
scheduling on 30-minute intervals. Bonneville Power states that it is
currently updating systems and work processes to implement 30-minute
scheduling in association with regional initiatives and that it
believes the changes, resources, and system impacts associated with the
implementation of scheduling at a 30-minute interval will be relatively
modest compared to what would be required to implement 15-minute
scheduling. Bonneville Power asserts that the systems, transmission
upgrades, and resources required to accommodate the increasingly
dynamic movements of power across the interconnection under 15-minute
scheduling would not be required under 30-minute scheduling. Tacoma
Power argues that it will determine the level of automation needed for
30-minute scheduling based on the experience it gains during
implementation of the Joint Initiative intra-hour program, but that
implementation of 15-minute scheduling intervals as discussed in the
Proposed Rule would require immediate automation of all the processes
for Tacoma Power to have any market presence.
iv. Requests for Additional Requirements
    84. Some commenters contend that transmission customers should be
encouraged or required to submit intra-hour schedules, arguing that the
Commission's objectives of lowering reserve costs can be reached only
if intra-hour scheduling is utilized in a consistent and predictable
manner.\112\ Bonneville Power argues that mandatory intra-hour
scheduling is necessary to achieve the reduction in reserve
requirements of 80 percent cited in its 2008 study.\113\ Idaho Power
and PNW Parties contend that VERs generally have a strong financial
incentive to maximize energy output and, therefore, may schedule for a
full hour to maximize benefits regardless of the availability of 15-
minute scheduling. WUTC recommends that the Commission couple the
implementation of intra-hour scheduling with measures to mitigate over-
scheduling by VERs, particularly when market conditions are favorable
for over-scheduling.
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    \112\ E.g., Bonneville Power; EEI; Idaho Power; MidAmerican;
NorthWestern; Puget; PNW Parties; WUTC.
    \113\ Bonneville Power (citing Bart McManus, Large Wind
Integration Challenges and Solutions for Operations/System
Reliability (2008). Bonneville Power clarifies that, in the study,
mandatory 10-minute scheduling on a 10-minute persistence basis
reduced the reserve requirements in the BPA region by 80 percent.
Bonneville Power also clarifies that this reduction only applies to
the source Balancing Authority, not the sink Balancing Authority).
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    85. Others recommend that the Commission provide incentives to use
intra-hour scheduling by eliminating the exemption of VERs from third-
tier generator imbalance penalties in Schedule 9 of the pro forma OATT,
which they argue would no longer be just and reasonable given the

Commission's proposed reforms.\114\ In addition to eliminating the
exemption from third-tier generation imbalance penalties, MidAmerican
suggests that an additional imbalance penalty tier be created for any
transmission customer that consistently fails to adjust schedules on an
intra-hour basis and creates significant variability. Avista recommends
that the Commission allow transmission providers to impose appropriate
penalties and recover the true costs of providing intra-hour schedules
from VERs that continue to schedule on an hourly basis.
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    \114\ E.g., Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.
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    86. Several commenters argue that intra-hour scheduling may not
achieve its intended benefits without additional reforms to augment
intra-hour scheduling practices.\115\ Some of these commenters assert
that the Commission should allow a public utility transmission provider
the flexibility to revise its energy imbalance settlement periods to
align with any intra-hour scheduling interval.\116\ Southern contends
that this will allow a public utility transmission provider to offer
appropriate incentives to customers to follow a given schedule and
limit the potential for exposure to uncompensated risks.