Integration of Variable Energy Resources, 41481-41546 [2012-15762]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 77, Number 135 (Friday, July 13, 2012)]
[Rules and Regulations]
[Pages 41481-41546]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-15762]



[[Page 41481]]

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

[[Page 41482]]


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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, (202) 502-8190.
Andrea Hilliard (Legal Information), Office of General Counsel--Energy 
Markets, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 502-8288.

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

[[Page 41483]]

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

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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

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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 https://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 https://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 https://www.seia.org/galleries/pdf/SMI-YIR-2011-ES.pdf.
    \29\ Annual Energy Outlook at 75, available at https://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 https://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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[[Page 41486]]

    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 https://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.
---------------------------------------------------------------------------

    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

[[Page 41487]]

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 https://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-

[[Page 41488]]

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

[[Page 41489]]

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

[[Page 41490]]

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

[[Page 41491]]

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

[[Page 41492]]

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 https://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

[[Page 41493]]

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

[[Page 41494]]

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

[[Page 41495]]

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

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

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

    \107\ E.g., Avista; California ISO; Duke; EEI; Idaho Power; 
NorthWestern; NV Energy; PNW Parties; Puget; Southern California 
Edison; Southern; Tres Amigas; WUTC.
---------------------------------------------------------------------------

    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

[[Page 41496]]

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

    \108\ E.g., Avista; Bonneville Power; EEI; Grant PUD; 
MidAmerican; NRECA; NorthWestern; PNW Parties; Puget; Snohomish PUD; 
Southern California Edison; Southwestern; Tacoma Power; TVA.
---------------------------------------------------------------------------

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

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

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

    \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).
---------------------------------------------------------------------------

    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

[[Page 41497]]

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

    \114\ E.g., Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.
---------------------------------------------------------------------------

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

    \115\ E.g., Avista; AWEA; RenewElec; Vote Solar.
    \116\ E.g., EEI; Duke; Idaho Power; Southern.
---------------------------------------------------------------------------

    87. However, Avista states that there are positives and negatives 
to either maintaining hourly settlement with intra-hour scheduling or 
modifying settlement intervals to coincide with intra-hour scheduling 
intervals. Avista asserts that conforming intra-hour schedules and 
imbalance settlement at 15-minute increments for all transmission 
schedules would result in alignment of scheduling and imbalance billing 
for all transactions and reduce gaming potential. Avista argues that 
the potential for gaming by transmission customers through the 
overcorrection of schedules in order to minimize imbalance charges may 
require a public utility transmission provider to carry regulation 
reserves in excess of what is needed. Midwest ISO agrees, citing a 
report from its Independent Market Monitor indicating that large 
changes in Net Scheduled Interchange caused by 15-minute intra-hour 
scheduling could lead to price volatility and negative operational 
impacts.\117\ Avista and Midwest ISO further state that conforming 
imbalance settlement with intra-hour schedules may require substantial 
and potentially costly office system changes, additional operations 
staff, and other costs incurred through the communication, metering, 
and storage of all customer data at 15-minute increments.
---------------------------------------------------------------------------

    \117\ Midwest ISO (Potomac Economics, 2008 State of the Market 
Report for the Midwest ISO, Docket No. ZZ09-4-000 at 169 [141] (June 
21, 2009)).
---------------------------------------------------------------------------

    88. Some commenters contend that intra-hour scheduling only governs 
the scheduling of flows on the transmission system and, by itself, does 
not necessarily affect the frequency with which generators are 
dispatched.\118\ AWEA and Invenergy Wind agree that a transition to 
sub-hourly dispatch is the key for increasing the flexibility of the 
power system and for reducing the amount of reserves that must be held, 
which in turn will reduce costs for consumers and enable cost effective 
integration of VERs. Commenters recommend that the Commission require 
public utility transmission providers to implement a sub-hourly, real-
time energy exchange that provides automated generation dispatch (such 
as an Efficient Dispatch Toolkit or the Energy Imbalance Market as 
adopted by the Southwest Power Pool and currently being studied in 
WECC). In AWEA's view, a market for sub-hourly energy would allow for 
netting of sub-hourly deviations and would provide price signals to 
incent greater sub-hourly flexibility.
---------------------------------------------------------------------------

    \118\ E.g., AWEA; CEERT; Invenergy Wind.
---------------------------------------------------------------------------

    89. AWEA acknowledges that changes to dispatch protocols and 
expansion of market options are being considered in regional efforts, 
but argues that progress is uncertain and unlikely to come to fruition 
in the near term. Iberdrola argues that intra-hour scheduling must be 
combined with intra-hour dispatch or market purchases to achieve the 
Commission's goals. Oregon and New Mexico PUC recommend that the 
Commission encourage reforms such as an Energy Imbalance Market or 15-
minute calculations of available transmission capability (ATC) as a 
complement to intra-hour scheduling. However, Bonneville Power suggests 
distinguishing between intra-hour scheduling outside of a market region 
and intra-hour dispatch in an organized market, arguing that the costs 
and benefits of each may be dramatically different. Bonneville Power 
explains that the resources devoted to implementing 15-minute 
scheduling may be better used to pursue the development of an organized 
market with frequent dispatch intervals.
    90. Some commenters assert that the Commission should consider 
changes to other aspects of electricity markets to facilitate intra-
hour scheduling.\119\ Invenergy Wind contends that consistent 
timeframes across all transmission and generation functions may lead to 
more efficient use of transmission capacity, regulation, and other 
ancillary services. American Clean Skies explains that the technology 
necessary to schedule transmission in 15-minute increments will also 
allow for scheduling reforms in the day-ahead market and the unit 
commitment process and, therefore, the Commission should require 15-
minute scheduling reforms in these areas as well. However, PJM asserts 
that real-time control issues do not exist day-ahead and, therefore, 
the Commission need not consider reforms to the day-ahead market.
---------------------------------------------------------------------------

    \119\ E.g., American Clean Skies; Invenergy Wind.
---------------------------------------------------------------------------

c. Commission Determination
    91. The Commission concludes that it is appropriate to act at this 
time to adopt the scheduling reforms set forth in the Proposed Rule. 
Specifically, 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. Our actions in this Final Rule will ensure that charges for 
generator imbalance service under Schedule 9 of the pro forma OATT and 
for other ancillary services through which reserve-related costs are 
recovered are just and reasonable and are not unduly 
discriminatory.\120\
---------------------------------------------------------------------------

    \120\ In section IV.C (Generator Regulation Service Capacity) 
infra, the Commission acknowledges that a range of capacity services 
could be used by public utility transmission providers to recover 
reserve-related costs.
---------------------------------------------------------------------------

    92. As noted in the Proposed Rule, many pro forma OATT 
requirements, including hourly scheduling protocols, were developed at 
a time when virtually all generation on the system could be scheduled 
with relative precision.\121\ As part of the Commission's regulatory 
responsibilities, we routinely review and, where appropriate, implement 
reforms to ensure the provision of service that remains just and 
reasonable and not unduly discriminatory. A similar review led the 
Commission in Order No. 890 to exempt VERs from the third-tier of 
generator imbalance penalties, given that VERs have a limited ability 
to accurately follow an hourly transmission schedule and, as a result, 
exposure to high imbalance penalties does not lessen their incentive to 
deviate from their schedule.\122\ In this Final Rule, we take an 
additional step to allow transmission customers the flexibility to 
adjust their transmission

[[Page 41498]]

schedules, in advance of real-time, to reflect the variability of 
output in generation, more accurate power production forecasts to 
predict output, and other changes in load profiles and system 
conditions.
---------------------------------------------------------------------------

    \121\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 38.
    \122\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 665.
---------------------------------------------------------------------------

    93. Specifically, the Commission affirms the preliminary finding in 
the Proposed Rule that existing hourly scheduling protocols expose 
transmission customers to excessive or unduly discriminatory generator 
imbalance charges.\123\ Under Schedule 9 of the pro forma OATT, 
generator imbalance charges are assessed on deviations between 
generator output and a delivery schedule over a single hour.\124\ 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 when the transmission customer knows or believes that 
generation output will change within the hour. The Commission concludes 
that 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. As a result of the 
intra-hour scheduling reforms of this Final Rule, the metric against 
which generator imbalances are measured will be more granular than 
under current hourly scheduling protocols.
---------------------------------------------------------------------------

    \123\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 37.
    \124\ Imbalance charges are calculated by multiplying the 
quantity of imbalance by a set percentage of incremental or 
decremental costs defined in three deviation bands. These charges 
are netted on a monthy basis and settled financially at the end of 
each month. For example, any deviations greater than  
7.5 percent (or 10 MW) of the scheduled transaction (applied hourly) 
will be settled at 125 percent of incremental costs or 75 percent of 
decremental costs. See OATT Schedule 9.
---------------------------------------------------------------------------

    94. The Commission expects that many types of entities, not only 
VERs, may benefit from the availability of intra-hour scheduling. Every 
transmission customer will have the ability to adjust its schedule at 
15-minute intervals to reflect changing conditions. This includes, for 
example, transmission customers that experience a within-hour forced 
outage or transmission customers taking delivery from energy 
constrained resources (such as flow-limited hydro-electric generators, 
emission-limited thermal generators, and energy storage resources), 
even if using point-to-point transmission internal to the system. For 
example, we note that Entergy voluntarily adopted intra-hour 
transmission scheduling without the presence of substantial VERs in an 
effort to manage fluctuations in output from qualifying facilities on 
its system.\125\ Based on this experience and the record in this 
proceeding, the Commission finds that intra-hour scheduling will 
provide a range of transmission customers with a necessary tool to 
mitigate exposure to Schedule 9 generator imbalance charges in light of 
changing conditions.
---------------------------------------------------------------------------

    \125\ See Entergy Serv. Inc., 111 FERC ] 61,314 (2005).
---------------------------------------------------------------------------

    95. The Commission also finds that, over time, implementation of 
intra-hour scheduling will allow public utility transmission providers 
to rely more on planned scheduling and dispatch procedures, and less on 
reserves, to maintain overall system balance. Under hourly scheduling 
protocols, the source balancing authority for a transaction is required 
to honor its transmission schedule across an entire hour, requiring the 
source balancing authority to have sufficient reserves in place to 
manage imbalances within the hour, i.e., maintain consistent delivery 
of the scheduled amount of energy to the sink balancing authority over 
the hour. This includes reserves to respond to variations in generation 
output that are moment-to-moment as well as longer-term, but occurring 
within the hour, represented by the solid line in Figure 1.

[[Page 41499]]

[GRAPHIC] [TIFF OMITTED] TR13JY12.000

    96. By moving from hourly to 15-minute scheduling intervals, the 
amount of imbalance energy for which the source balancing authority is 
potentially responsible can be reduced, as reflected in Figure 1. This 
can lead to a corresponding reduction in the amount of capacity held to 
provide that energy and, in turn, lower reserve-related costs for the 
source balancing authority, and ultimately consumers. Therefore, the 
Commission also finds that implementation of intra-hour schedules is 
necessary in order to ensure that charges for ancillary services 
through which reserve-related costs are recovered are just and 
reasonable and not unduly discriminatory.\126\
---------------------------------------------------------------------------

    \126\ One mechanism that could be used to recover reserve-
related costs is generator regulation service. The Commission 
provides guidance regarding the development of generation regulation 
charges in section IV.C.2 (Mechanics of Generator Regulation Charge) 
infra. Among other things, public utility transmission providers 
should consider the extent to which transmission customers are using 
intra-hour scheduling in evaluating whether to require different 
transmission customers to provide or otherwise account for different 
quantities of generator regulation service.
---------------------------------------------------------------------------

    97. For these reasons, the Commission adopts the proposal set forth 
in the Proposed Rule and directs public utility transmission providers, 
consistent with the compliance deadlines addressed below, to revise 
their OATTs to provide an opportunity for transmission customers to 
submit transmission schedules at 15-minute intervals. In response to 
Bonneville Power and Xcel, the Commission clarifies that this 
requirement is intended to allow transmission customers to both modify 
existing schedules as well as create new schedules, provided that the 
transmission customer has a transmission reservation in place.\127\ The 
ability to create new transmission schedules within the hour will be 
particularly important to resources that may seek to provide intra-hour 
energy products, as discussed further below.
---------------------------------------------------------------------------

    \127\ To be clear, this Final Rule does not alter the 
transmission products of the pro forma OATT and, therefore, 
implementation of intra-hour scheduling does not require (yet would 
not preclude) the intra-hour calculation of ATC or sale of 
transmission service.
---------------------------------------------------------------------------

    98. The Commission notes that most commenters support the practice 
of intra-hour scheduling, with disagreement focused primarily on the 
frequency of schedule adjustments and whether changes to existing 
scheduling should be paired with other reforms. Balancing the competing 
considerations raised by commenters, the Commission concludes that a 
15-minute scheduling interval is appropriate and declines to impose 
additional reforms at this time. The Commission appreciates that 
implementation of other reforms, such as intra-hour imbalance 
settlement, an intra-hour transmission product, increasing the 
frequency of resource commitment through sub-hourly dispatch, or the 
formation of intra-hour imbalance markets, could yield additional 
benefits for public utility transmission providers and their customers. 
However, these additional reforms can have significant costs. The 
Commission's review of the record in this proceeding suggests that a 
more measured approach is appropriate to take at this time.\128\
---------------------------------------------------------------------------

    \128\ As noted below, public utility transmission providers will 
have an opportunity on compliance to demonstrate that alternative 
intra-hour scheduling proposals are consistent with or superior to 
the intra-hour scheduling requirements of this Final Rule. Such a 
proposal could include one or more of the additional reforms 
requested by commenters, such as the formation of intra-hour 
imbalance markets.
---------------------------------------------------------------------------

    99. The Commission acknowledges that implementation of intra-hour 
scheduling can result in a shift of responsibility for holding certain 
reserves away from the source balancing

[[Page 41500]]

authority for export transactions.\129\ As explained above, allowing 
for more granular transmission schedules can reduce the amount of 
variation in generation output for which the source balancing authority 
is responsible. The Commission appreciates that, from the sink 
balancing authority's perspective, scheduling at shorter intervals may 
result in the purchaser of energy having to manage more frequent 
changes in scheduled deliveries as compared to scheduling at hourly 
intervals. As indicated in Figure 2, a purchaser under existing hourly 
scheduling protocols receives a fixed quantity of energy over the hour 
from the source balancing authority, whereas use of 15-minute intervals 
could result in fluctuating deliveries across the hour.
---------------------------------------------------------------------------

    \129\ E.g., Xcel; Iberdrola.
    [GRAPHIC] [TIFF OMITTED] TR13JY12.001
    
    To the extent the purchaser desires to continue receiving a 
constant delivery of energy across the hour, represented by the dotted 
line in Figure 2, it may be required to obtain that energy from the 
market.\130\ The Commission concludes that this is an appropriate 
division of responsibility, as opposed to the current hourly system 
which places all responsibility for managing variations in generation 
output across the hour solely on the source balancing authority. Within 
the hour, the source balancing authority retains its responsibility of 
providing the energy needed for the VER to meet its schedule, while the 
purchaser takes on the responsibility of managing more frequent 
deliveries of scheduled energy.
---------------------------------------------------------------------------

    \130\ For example, sellers of VER energy could have existing 
contractual commitments to deliver at constant volumes over 
specified periods.
---------------------------------------------------------------------------

    100. By shifting responsibility for managing certain variations in 
generation output to the purchasing entity, purchasing entities will 
have greater incentive to manage changes in scheduled deliveries from 
15-minute interval to 15-minute interval and the portfolio of resources 
that ultimately manage total VER variability will likely be more cost-
effective than under current practices. Specifically, a portfolio of 
resources that respond over a range of time scales, from very fast to 
relatively slow, is lower cost than a portfolio that relies on 
resources designed to manage only the short-run variability of 
VERs.\131\ For instance, portfolio cost savings could result from using 
a combination of expensive resources with automated generator control 
and less expensive resources that provide following service rather than 
using only resources with automated generator control. While the source 
balancing area could choose to manage VER variability with a portfolio 
of resources that respond over a range of time, it has little incentive 
to do so because any additional costs can be recovered from 
transmission customers. We expect use of a portfolio of resources to 
lower the overall cost of managing VER variability. The Commission 
anticipates that buyers and sellers also may respond by developing 
intra-hour balancing products. EPSA notes that the additional market 
liquidity created by the ability to schedule transmission intra-hourly 
can provide opportunities for existing resources to manage system

[[Page 41501]]

variability by offering within-hour energy products. This is equally 
true for market participants seeking to maximize the value of their 
resources, or lower their purchased power costs, through intra-hour 
trading. As the liquidity of intra-hour energy products stabilizes, 
market participants also may begin to commit or otherwise acquire fewer 
reserves in advance, with the knowledge that they can purchase 
additional reserves on an as-needed basis from third parties. Requiring 
public utility transmission providers to offer intra-hour scheduling is 
a necessary predicate to facilitate these market opportunities.\132\
---------------------------------------------------------------------------

    \131\ See e.g., J. Apt, The Spectrum of Power from Wind 
Turbines. Journal of Power Sources, Vol. 169, No. 2, at 369-374 
(2007); cited at RenewElec comments at note 4.
    \132\ For example, the Joint Initiative has implemented an 
electronic platform to facilitate bilateral intra-hour transactions, 
the Intra-hour Transaction Accelerator Platform (I-TAP), also 
referred to as the WebExchange. See https://www.columbiagrid.org/itap-overview.cfm.
---------------------------------------------------------------------------

    101. Notwithstanding broad support in comments for some version of 
intra-hour scheduling, as noted above, there was significant 
disagreement in the comments as to the appropriate time interval. Some 
commenters supported the 15-minute interval proposed by the 
Commission,\133\ while others argued for either shorter (e.g., 5-
minute) or longer (e.g., 30-minute) scheduling intervals.\134\ In 
evaluating these comments, the Commission has balanced the competing 
interests of allowing transmission customers to more closely match 
schedules with anticipated generation output against not unduly 
burdening public utility transmission providers in implementing the 
intra-hour scheduling reform. The Commission concludes that adoption of 
a 15-minute scheduling interval for purposes of the pro forma OATT is 
reasonable. In its comments on the NOI, NERC states that the ideal 
scheduling increment would be between 5 and 15 minutes depending on 
system characteristics.\135\ NERC reasoned that, while balancing 
authorities that schedule energy transactions on an hourly basis may 
have sufficient regulation resources to maintain the schedule for the 
hour, reducing scheduling intervals to ten minutes, for example, could 
make economically dispatchable generators in an adjacent balancing 
authority available to provide necessary ramping capability through an 
interconnection.\136\ The Commission agrees and, as discussed above, 
anticipates that the availability of intra-hour scheduling at 15-minute 
intervals will facilitate the development of ramping products to manage 
variability in generation output more effectively. For these reasons we 
adopt 15-minute transmission scheduling as proposed.
---------------------------------------------------------------------------

    \133\ E.g., A123; Alstom Grid; ACSF; Argonne National Lab; BP 
Companies; CESA; CEERT; Center for Rural Affairs; Clean Line; CGC; 
Defenders of Wildlife; EPSA; Exelon; First Wind; Independent Energy 
Producers; NaturEner; Organization of Midwest ISO States; Oregon & 
New Mexico PUC; Powerex; Public Interest Organizations; SWEA; Tres 
Amigas; Viridity Energy; Western Grid; Xcel.
    \134\ Compare Environmental Defense Fund; FriiPower; Independent 
Power Producers Coalition-West; RenewElec; SEIA; Vestas; and Vote 
Solar (advocates of shorter) with Bonneville Power; California PUC; 
CMUA; Montana PSC; NorthWestern; Puget; Snohomish County PUD; 
Southern California Edison; WUTC (advocates of longer).
    \135\ NERC April 12, 2010 Response to NOI (NERC NOI Comments).
    \136\ NERC NOI Comments.
---------------------------------------------------------------------------

    102. In adopting a 15-minute transmission scheduling interval, we 
recognize that the cost of moving from hourly to 15-minute transmission 
scheduling could be substantial. Several transmission providers state 
that costs will depend heavily on the extent to which intra-hour 
scheduling is actually used by transmission customers, estimating 
staffing costs to be in the range of $1-2 million per year if widely 
used.\137\ While these costs are not insignificant, greater use of 
intra-hour schedules means that more transmission customers are 
mitigating exposure to Schedule 9 generator imbalance charges and 
providing greater opportunities for public utility transmission 
providers to lower reserve-related costs. Commenters generally agree 
that the cost of implementing intra-hour scheduling will correlate to 
usage, with lower costs in those systems with fewer intra-hour 
schedules. In contrast, substantial use of intra-hour scheduling would 
affirm the usefulness of the option for transmission customers, 
justifying the added expense of processing a larger number of 
transmission schedules.
---------------------------------------------------------------------------

    \137\ E.g., Avista; NRECA. To the extent intra-hour scheduling 
is not widely used by transmission customers, NRECA states its 
members likely could implement scheduling at 15-minute intervals 
with software modifications in the range of $50,000 per company, 
without additional staffing requirements.
---------------------------------------------------------------------------

    103. Many of the costs cited by commenters as being specific to 15-
minute scheduling are related to the automation of systems used to 
process transmission schedules and verify cross-balancing authority 
aggregate schedules. The Commission notes that it is not mandating 
automation of scheduling practices, although we expect that each public 
utility transmission provider will consider whether automation of 
certain aspects of its system are necessary to implement scheduling at 
15-minute intervals. To the extent a public utility transmission 
provider automates scheduling processes in response to increased 
scheduling activity, the Commission agrees with NaturEner and 
Independent Power Producers Coalition-West that automation of these 
processes represents a secondary benefit of our transmission scheduling 
reform. Several Commission staff audits have uncovered errors related 
to manual processing of transmission schedules.\138\ These errors 
resulted in a transmission customer submitting a transmission schedule 
that resulted in a higher curtailment priority than the underlying 
transmission service reservation provided, allowed use of firm network 
service to deliver energy from resources that were not designated 
resources and allowed use of network transmission service to deliver a 
sale to a third party. As a result of these errors, the transmission 
customer may have gained access to transmission service that was not 
otherwise available, may have inappropriately gained additional 
protection from curtailment, and avoided payment for point-to-point 
transmission service. Increased automation of schedule process can 
reduce such errors and, in turn, ensure that the provision of 
transmission service is consistent with the pro forma OATT.
---------------------------------------------------------------------------

    \138\ E.g., Puget Sound Energy, Docket No. PA07-1-000 at 25-27; 
MidAmerican Energy Co., Audit Report, 112 FERC ] 61,346 at PP 30-34 
(2005); and Public Service Company of Colorado, Docket No. PA05-1-
000 at 9-11.
---------------------------------------------------------------------------

    104. Some commenters raising concerns regarding the cost of 
implementing intra-hour scheduling imply that the proposed scheduling 
reforms would require changes in settlement procedures for imbalance 
service or the frequency of resource commitment through sub-hourly 
dispatch, which they state would require significant investments. For 
example, EEI and PNW Parties caution that these additional activities 
would affect computer systems, such as energy management and accounting 
systems.\139\ MidAmerican estimates that upgrading such systems would 
cost $2.0-2.3 million. Other commenters, however, encourage the 
Commission to require intra-hour imbalance settlement and sub-hourly 
dispatch in order to align intra-hour scheduling with financial 
settlements and resource commitment. The Commission clarifies that the 
requirements of this Final Rule apply to scheduling practices, not 
imbalance settlement or sub-hourly dispatch. Public utility 
transmission providers may continue to calculate pro forma Schedule 9 
generator imbalance charges on an hourly basis under the pro forma

[[Page 41502]]

OATT and rely on hourly resource commitment practices.\140\
---------------------------------------------------------------------------

    \139\ Eg., EEI; PNW Parties.
    \140\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 722; 
Order No. 890-A, FERC Stats. & Regs. ] 61,297 at P 325 & n.117.
---------------------------------------------------------------------------

    105. Notwithstanding the continued ability of public utility 
transmission providers to rely on hourly calculation of Schedule 9 
generator imbalances, as a result of the intra-hour scheduling reforms 
of this Final Rule, the metric against which generator imbalances are 
measured will be more granular than under current hourly scheduling 
protocols. To the extent a public utility transmission provider 
believes that aligning the imbalance settlement with the intra-hour 
scheduling interval or implementing sub-hourly dispatch will result in 
more efficient operations, provide appropriate price signals to 
customers, or address other potential issues, it may seek any 
authorizations necessary from the Commission to do so under section 205 
of the FPA.\141\ Such proposals could be submitted contemporaneously 
with the compliance filing in response to this Final Rule or at such 
other time the public utility transmission provider believes 
appropriate.
---------------------------------------------------------------------------

    \141\ For example, PNW Parties and Idaho Power note that the 
financial incentives some transmission customers have to maximize 
output over an hour may in some instances counteract financial 
incentives to adjust transmission schedules on a 15-minute basis.
---------------------------------------------------------------------------

    106. Several commenters request that the Commission allow for 
regional variation in scheduling protocols.\142\ In the Western 
Interconnection, many public utility transmission providers already 
have implemented some form of intra-hour scheduling at 30-minute 
intervals as part of an effort to enhance the operation of bilateral 
markets in the Western Interconnection.\143\ Other tools recently 
implemented in the West include the I-TAP electronic platform to 
schedule energy and request transmission, the Dynamic Scheduling System 
to facilitate dynamic scheduling,\144\ and the ACE Diversity 
Interchange Program to allow netting of momentary imbalances across 
participating balancing authority footprints.\145\ Public utility 
transmission providers, state regulators, and others in the West are 
studying the impact of these recent initiatives, as well as the 
potential benefits and costs of pursuing additional market enhancements 
in the future, such as formation of an energy imbalance market. The 
Commission acknowledges that future market enhancements in addition to 
existing 30-minute scheduling practices and the above-referenced tools, 
might yield equivalent or greater benefits to transmission customers 
and public utility transmission providers when compared to reducing the 
scheduling interval from 30 to 15 minutes and therefore could be 
consistent with or superior to the Final Rule's intra-hour scheduling 
requirements.
---------------------------------------------------------------------------

    \142\ E.g., Avista; Bonneville Power; California ISO; CESA; 
CMUA; California PUC; Detroit Edison; EEI; FirstEnergy; Grant PUD; 
Idaho Power; Independent Power Producers Coalition-West; ISO/RTO 
Council; Midwest ISO; National Grid; Northwestern; NRECA; New York 
ISO; NV Energy; Pacific Gas & Electric; PJM; PNW Parties; Public 
Power Council; Puget; SMUD; Tacoma Power; WUTC; and WestConnect.
    \143\ See e.g., Arizona Public Service Co., 137 FERC ] 61,023 
(2011), NorthWestern Corp., 136 FERC ] 61,119 (2011).
    \144\ See Joint Initiative.
    \145\ See NERC, DRAFT Reliability Guideline: ACE Diversity 
Interchange (June 2012), available at https://www.nerc.com/docs/oc/rs/Draft%20ADI%20Reliability%20Guideline%20-%20V1%20060112.pdf.
---------------------------------------------------------------------------

    107. The Commission therefore affirms the ability of public utility 
transmission providers to submit alternative proposals that are 
consistent with or superior to the intra-hour scheduling requirements 
of this Final Rule and are otherwise just and reasonable and not unduly 
discriminatory or preferential.\146\ To make such a showing, a public 
utility transmission provider must demonstrate in its compliance filing 
how its proposal provides equivalent or greater opportunities for 
transmission customers to mitigate Schedule 9 generator imbalance 
charges, and for the public utility transmission provider to lower its 
reserve-related costs, when compared to implementation of the intra-
hour scheduling requirements of this Final Rule under market practices 
currently in place within the region, including tools referenced above 
that already have been implemented in the West.\147\ The public utility 
transmission provider must include in its compliance filing the tariff 
provisions necessary to implement its proposal, including the interval 
at which transmission customers may submit transmission schedules. The 
public utility transmission provider also must address how its proposed 
scheduling interval is consistent with other scheduling practices 
within its region. Finally, in recognition that implementation of 
intra-hour scheduling can result in a shift of responsibility for 
holding certain reserves away from the source balancing authority for 
export transactions, public utility transmission providers may consider 
the extent to which alternative proposals result in savings to 
transmission customers across multiple public utility transmission 
provider systems when making the demonstration required above.
---------------------------------------------------------------------------

    \146\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,770 
(permitting public utility transmission providers to propose tariff 
modifications that are consistent with or superior to the 
requirements of the pro forma OATT).
    \147\ To the extent such an alternative proposal includes a 
commitment to develop and implement additional market enhancements 
in the future, the public utility transmission provider must provide 
in its compliance filing: A commitment by senior management to 
develop and implement the proposal; a description of collaborative 
efforts to date and timeline for future efforts in support of 
developing the proposal; and, the date by which the proposed market 
enhancement will be implemented.
---------------------------------------------------------------------------

    108. Turning to other issues raised by commenters, the Commission 
is not convinced by arguments that the current exemption from third-
tier generator imbalance penalties for intermittent resources should be 
eliminated to create an incentive for VERs to take advantage of the 
option to update transmission schedules every 15 minutes.\148\ In Order 
No. 890, the Commission found intermittent generators cannot always 
accurately follow their schedules and that high penalties will not 
lessen the incentive to deviate from their schedules.\149\ While the 
implementation of 15-minute scheduling provides an opportunity for VERs 
to better align transmission schedules with actual generation, the 
Commission continues to believe that third-tier generator imbalance 
penalties are unduly punitive for VERs given their relative inability 
to accurately follow schedules whether submitted on an hourly or 15-
minute interval. The Commission concludes that the ability to avoid 
penalties in the first two tiers of generator imbalance charges will 
provide a sufficient incentive for VERs to adjust transmission 
schedules, to the extent they believe such adjustments will mitigate 
exposure to Schedule 9 generator imbalance charges. If a public utility 
transmission provider believes it necessary to address intentional 
deviations, it may propose revisions to Schedule 9 generator imbalance 
service pursuant to section 205 of the FPA.\150\ Such proposals would 
need to demonstrate that VERs are not adjusting their transmission 
schedules despite their reasonable ability to foresee that

[[Page 41503]]

output will deviate significantly from existing transmission 
schedules.\151\
---------------------------------------------------------------------------

    \148\ E.g., Avista; EEI; Idaho Power; MidAmerican; Puget; WUTC.
    \149\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 665.
    \150\ Cf. id. P 676 (noting the ability of public utility 
transmission providers to propose additional imbalance penalties for 
intentional deviations). Alternatively, the public utility 
transmission provider may propose alternative designs for other 
ancillary services rates to, for example, offer lower rates to those 
transmission customers committing to use intra-hour scheduling.
    \151\ The Commission notes that there is a relationship between 
a public utility transmission provider's potential need for 
alternative imbalance charge structures and the period used for 
imbalance settlements. Reinstating third-tier imbalance penalties in 
combination with shortened imbalance settlements would more likely 
punish VERs for variability that they cannot control, contrary to 
the exemption granted in Order No. 890 and affirmed here.
---------------------------------------------------------------------------

    109. The Commission acknowledges comments made by some, 
particularly in the Pacific Northwest, asserting that the benefits of 
intra-hour scheduling will not be fully realized if non-jurisdictional 
entities do not adopt a consistent scheduling interval.\152\ However, 
the Commission does not believe that limitations in our ratemaking 
jurisdiction over non-public utilities should stop us from moving ahead 
with reforms applicable to public utilities simply because the impact 
of those reforms might be more significant with participation by all 
entities. As explained above, requiring all public utility transmission 
providers to offer 15-minute transmission scheduling will enable public 
utility transmission providers and their customers to manage system 
variability more effectively. Therefore, the Commission is hopeful that 
non-jurisdictional transmission providers will voluntarily choose to 
implement 15-minute transmission scheduling in order to better manage 
variations in generation output. We understand that the existence of 
compatible business practices within a region is beneficial, and we 
encourage both jurisdictional and non-jurisdictional transmission 
providers to continue to coordinate and collaborate in order to 
maintain the continuity of the system and address issues as they arise. 
This includes collaboration in the development of any alternative 
compliance proposals developed by public utility transmission 
providers.
---------------------------------------------------------------------------

    \152\  E.g., Avista; California ISO; Duke; Idaho Power; 
NorthWestern; NV Energy; PNW Parties; Puget; Southern California 
Edison; Southern; Tres Amigas.
---------------------------------------------------------------------------

    110. The Commission disagrees with comments by Southern and others 
that different scheduling intervals between jurisdictional and non-
jurisdictional transmission providers may negatively affect reliability 
within an interconnection.\153\ In the event a non-jurisdictional 
transmission provider only accepts hourly schedules, any attempt to 
submit an intra-hour schedule for delivery to the non-jurisdictional 
transmission provider would be rejected, as several commenters 
note.\154\ This may lead to an inability to implement 15-minute 
scheduling fully and, in turn, could result in less effective 
management of system variability. However, the Commission does not 
believe that it would create any reliability challenges beyond those 
that exist today under hourly scheduling protocols. The Commission 
notes that voluntary efforts to implement intra-hour scheduling on 30-
minute intervals in the Western Interconnection referenced above have 
not been uniformly applied, yet do not appear to have negatively 
affected reliability.
---------------------------------------------------------------------------

    \153\ E.g., EEI; Idaho Power; NorthWestern; Southern; Tacoma 
Power.
    \154\ E.g., PNW Parties; Puget; WUTC.
---------------------------------------------------------------------------

    111. In response to concerns raised by Snohomish County PUD and 
Grays Harbor PUD regarding ``slice'' contracts with Bonneville Power, 
the Commission acknowledges that some existing power supply 
arrangements may not be flexible enough to take advantage of the 
benefits of intra-hour scheduling. Over time, the Commission 
anticipates that the market will respond to the availability of intra-
hour scheduling through the development of new balancing products as 
well as modifications of existing arrangements where appropriate. 
However, in the case where the terms of an existing contract are 
inconsistent with intra-hour scheduling and cannot be modified, the 
Commission appreciates that the benefits of intra-hour scheduling may 
not be available with respect to that particular transaction.
    112. In response to comments by WestConnect and NorthWestern that a 
15-minute scheduling interval is inconsistent with the standard 20-
minute generator ramp rate used in the West, we note that many of the 
Joint Initiative transmission providers--including members from 
WestConnect--have already implemented a 10-minute ramp rate to 
accommodate 30-minute transmission schedules. To the extent changes in 
ramping are necessary to support use of a 15-minute transmission 
schedules, it does not appear that such changes present a significant 
impediment for public utility transmission providers.
    113. A number of commenters question the applicability of the 
intra-hour scheduling requirements to public utility transmission 
providers in RTO and ISO regions.\155\ The Commission clarifies that 
the implementation of 15-minute transmission scheduling will only apply 
to intertie transactions in organized wholesale energy markets. The 
Commission finds that a consistent scheduling interval for transactions 
among all public utility transmission providers, including RTOs, is 
necessary in order to attain the benefits of intra-hour scheduling 
noted above. Additional reforms to other markets requested by 
commenters, such as adjustments to day-ahead markets, are beyond the 
scope of this rulemaking.
---------------------------------------------------------------------------

    \155\ E.g., AWEA; Iberdrola; ISO New England; Massachusetts DPU; 
PJM; Public Interest Organizations; RENEW; Sunflower and Mid-Kansas; 
Western Farmers.
---------------------------------------------------------------------------

2. Implementation of Intra-Hour Scheduling
    114. Commenters raise a number of additional issues related to how 
the intra-hour scheduling requirements adopted in this Final Rule 
should be implemented. The Commission addresses these issues below, 
including the following: (1) The appropriate notification period for 
submitting transmission schedules; (2) the recovery of costs associated 
with implementing intra-hour scheduling; (3) clarifications regarding 
the definition of transmission schedule, curtailment priorities, and 
calculations of ATC; (4) review of NERC reliability standards and NAESB 
business practices; and (5) other issues related to high voltage direct 
current (HVDC) transmission lines, dynamic scheduling, and the 
geographic location of resources used to provide reserves.
a. Notification Time for Submission of Transmission Schedule
i. Commission Proposal
    115. In the Proposed Rule, the Commission proposed to allow all 
transmission customers the option of submitting intra-hour schedules up 
to 15 minutes before each scheduling interval.\156\
---------------------------------------------------------------------------

    \156\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 41.
---------------------------------------------------------------------------

ii. Comments
    116. Several commenters ask the Commission to retain the existing 
20-minute notification time for submission of transmission schedules, 
arguing that schedules should be submitted no later than 20 minutes 
prior to the start of the schedule as required by NERC Reliability 
Standards INT-005, INT-006, INT-008, and NAESB WEQ-004 Appendix D.\157\ 
Commenters contend that allowing only 15 minutes between schedule 
submission and start would not provide enough time for transmission 
operators to adequately evaluate, approve, and implement transmission 
schedules. ISO/RTO Council adds that changing to a 15-minute notice 
period will require

[[Page 41504]]

transmission operators to change their current systems and increase 
staff levels for processing transmission schedule requests. PJM 
comments that the 20-minute notification deadline is an established 
industry standard and that it should not be changed to 15 minutes.
---------------------------------------------------------------------------

    \157\ E.g., Duke; EEI; Entergy; NRECA; PJM; Puget; Southern.
---------------------------------------------------------------------------

    117. Although not opposed to the Commission's proposal, NaturEner 
states that a shorter notification period would result in abbreviated 
response times for everyone in the scheduling process, including 
transmission customers. NaturEner asks the Commission to clarify that 
transmission providers have the discretion to accept schedule changes 
after the notification deadline. NaturEner contends that inclusion of 
such a clarification both supports the reform's underlying rationales 
and avoids any unnecessary future confusion regarding whether a 
balancing authority or transmission provider possesses such discretion.
iii. Commission Determination
    118. The Commission will retain the existing 20-minute prior 
notification period for the submission of a transmission schedule and 
not adopt its proposal. The Commission agrees with commenters that the 
existing 20-minute prior notification period is needed to adequately 
evaluate, approve and implement transmission schedules. Accordingly, 
the Commission retains the existing notification period set forth in 
sections 13.8 and 14.6 of the pro forma OATT, which permits scheduling 
changes up to 20 minutes (or a reasonable time that is generally 
accepted in the region and is consistent and adhered to by the 
transmission provider) before the start of the next schedule change 
provided that the delivering party and receiving party also agree to 
the schedule modification. In response to NaturEner, the existing 
language of the pro forma OATT provides adequate flexibility for 
transmission providers to adopt alternative deadlines for accepting 
scheduling changes.
b. Recovery of Intra-Hour Scheduling Costs
i. Commission Proposal
    119. In the Proposed Rule, the Commission proposed to allow public 
utility transmission providers to recover any costs incurred to 
implement the proposed intra-hour scheduling reform pursuant to 
Schedule 1 of a transmission provider's OATT.\158\
---------------------------------------------------------------------------

    \158\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 41.
---------------------------------------------------------------------------

ii. Comments
    120. Several commenters support the Commission's proposal, arguing 
that the benefits of intra-hour scheduling apply to more than VERs and, 
thus, costs relating to the implementation of intra-hour scheduling 
should be allocated to all transmission customers under Schedule 1 of 
the pro forma OATT.\159\ For example, NextEra contends that intra-hour 
scheduling would provide long-term benefits for all customers through 
savings on reserve procurement. Public Interest Organizations agree, 
arguing that the initial costs of establishing 15-minute scheduling are 
an upfront investment that will yield exponential returns over time in 
the form of direct economic savings from increased grid efficiency and 
reliability, as well as energy security, greenhouse gas and other 
pollutant reductions, and job creation that accompanies increased 
renewable VER penetration. Center for Rural Affairs supports recovery 
of intra-hour scheduling costs to all beneficiaries through Schedule 1 
in order to mitigate any challenge that this reform may present for 
small transmission providers, especially in rural communities with 
smaller areas of distribution. NaturEner points to the Joint Initiative 
as an example of allocating the hardware and software costs associated 
with implementation of intra-hour scheduling to all participants using 
the intra-hour scheduling system, i.e., the balancing authorities, 
transmission providers, and transmission customers. While Organization 
of Midwest ISO States supports the proposal, it asks that a clear 
showing of the costs incurred to implement intra-hour scheduling be 
required prior to allowing for recovery of those costs.
---------------------------------------------------------------------------

    \159\ E.g., Environmental Defense Fund; NextEra; Public Interest 
Organizations.
---------------------------------------------------------------------------

    121. Other commenters disagree with the Commission's proposal to 
allow the costs associated with implementing intra-hour scheduling to 
be recovered through Schedule 1 and, instead, contend that such costs 
should be allocated to VERs and their customers.\160\ These commenters 
argue that intra-hour scheduling will be predominantly used by and 
benefit VERs and their customers.\161\ ELCON contends that traditional 
generation resources do not require intra-hour scheduling. In the 
Pacific Northwest, WUTC claims that intra-hour scheduling would be 
utilized almost exclusively by wind and other VERs, and not by thermal 
or hydropower resources. WUTC agrees that assignment of costs to those 
who cause them is essential to fair and just rates and to economic 
efficiency. Puget agrees that the only parties to benefit from 15-
minute scheduling are VERs that are potentially able to reduce Schedule 
9 generator imbalance charges by adjusting their schedules within the 
hour in response to changing wind conditions. Natural Gas argues that 
strict adherence to cost causation principles is central to ensuring 
that the proposals are limited to removing barriers and do not have the 
unintended consequence of subsidization and, ultimately, departure from 
the central precept of fuel neutrality.
---------------------------------------------------------------------------

    \160\ E.g., Avista; ELCON; Grant PUD; Montana PSC; Natural Gas; 
NorthWestern; NRECA; Puget; WUTC.
    \161\ E.g., Avista; ELCON; Grant PUD; MidAmerican; NorthWestern; 
NRECA; Puget; WUTC.
---------------------------------------------------------------------------

    122. Montana PSC states that traditional generation choosing to 
utilize intra-hour scheduling should be allocated a portion of 
implementation costs; however, absent this election VERs should be 
responsible for all costs related to development, operations, and 
maintenance of intra-hour scheduling.\162\ NRECA similarly contends 
that, if transmission customers other than VERs make use of the new 
scheduling regime, it would be appropriate for those entities to share 
in the cost through Schedule 1 charges. Grant PUD argues that there is 
no guarantee that other resources may benefit from a shorter scheduling 
period and that some resources may actually incur costs to maintain 15-
minute schedules, in which case they would pay twice for the shift to 
shorter schedules.
---------------------------------------------------------------------------

    \162\ Similarly, NorthWestern asserts that unless intra-hour 
scheduling is made mandatory for all transmission customers, the 
VERs opting to use intra-hour scheduling should pay for the 
increased scheduling flexibility and the non VER customers should 
not be required to subsidize any particular generator type.
---------------------------------------------------------------------------

    123. Avista asserts that allowing recovery through Schedule 1 will 
allocate costs not only to all transmission customers, but also to 
bundled retail native load customers. Avista argues that native load 
customers achieve no cost savings when a VER is located within a 
balancing authority area and is used to serve load within the same 
balancing area. Avista states that in this situation the native load 
customers bear all of the costs associated with following the output of 
the VER and do not need or benefit from intra-hour scheduling. Thus, 
Avista requests that none of the costs of implementing intra-hour 
scheduling be

[[Page 41505]]

borne by a transmission provider's bundled retail native load 
customers.
    124. Several of these commenters recommend that the Commission 
consider other mechanisms for recovering the costs of implementing 
intra-hour scheduling as opposed to a broad cost allocation scheme 
through Schedule 1.\163\ For example, Avista asks the Commission to 
allow a transmission provider to directly assign the costs of 
implementing these reforms to the VER transmission customers that are 
the cause of such reforms through an appropriate charge included in 
either Schedule 1 or Schedule 10. NRECA argues that there is more than 
one method that a public utility transmission provider could use to 
recover costs and requests that the Commission provide public utility 
transmission providers the flexibility to choose the method that works 
best for each system and demonstrate a just and reasonable rate 
pursuant to section 205 of the FPA. NRECA also urges the Commission to 
include costs incurred to comply with any new Reliability Standards 
that ensue from the Final Rule.
---------------------------------------------------------------------------

    \163\ E.g., Avista; Grant PUD; NRECA; Puget.
---------------------------------------------------------------------------

iii. Commission Determination
    125. The Commission adopts its proposal and allows public utility 
transmission providers to recover any costs incurred to implement the 
intra-hour scheduling reforms adopted in this Final Rule pursuant to 
Schedule 1 of the transmission provider's OATT. The Commission is not 
persuaded by commenters opposing the proposal that recovery of these 
costs through Schedule 1 will result in an overly broad assignment of 
costs. Such commenters argue that only a subset of transmission 
customers is likely to use intra-hour scheduling and that only those 
customers should bear the cost of implementing intra-hour scheduling 
reforms. The Commission disagrees. As discussed above, intra-hour 
scheduling provides all transmission customers with the tools needed to 
mitigate exposure to Schedule 9 generator imbalance charges in light of 
changing conditions.\164\ Implementation of intra-hour scheduling is 
also necessary to the extent sellers wish to develop intra-hour energy 
products to maximize the value of available resources or to allow load 
serving entities to lower purchased power costs.\165\ The Commission 
finds that these benefits will be spread broadly across customer 
classes.
---------------------------------------------------------------------------

    \164\ See supra Sec.  IV.A.1 (Intra-Hour Scheduling 
Requirement).
    \165\ Id.
---------------------------------------------------------------------------

    126. Moreover, commenters opposing the Commission's proposal fail 
to reconcile their position with existing approaches used to recover 
scheduling-related costs under Schedule 1 of the pro forma OATT. 
Transmission providers do not currently parse scheduling costs into, 
for example, categories for network customers and point-to-point 
customers even though at times scheduling reforms have focused on one 
set of customers and not the other.\166\ Rather, transmission customers 
as a whole have allocated the costs of scheduling-related activities 
through Schedule 1: Scheduling, System Control and Dispatch Service, 
and relevant allocations to retail native load have been made by public 
utility transmission providers. Commenters have failed to justify why 
the Commission should depart from this precedent during implementation 
of intra-hour scheduling practices.
---------------------------------------------------------------------------

    \166\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 770.
---------------------------------------------------------------------------

    127. In response to NRECA, the Commission's focus in this 
proceeding is on the implementation of intra-hour scheduling and, as 
relevant here, the recovery of scheduling-related implementation costs 
pursuant to Schedule 1 of the pro forma OATT. The Commission did not 
propose to address, and does not address here, recovery of other costs 
associated with compliance with NERC Reliability Standards.
c. Clarify Proposed Rule Language
i. Comments
    128. Commenters ask the Commission to clarify what is intended by 
the terms schedule and scheduling interval. Southern and EEI state that 
the term ``schedule'' is not well defined throughout the electric 
industry and requests that the Commission clarify that ``schedule'' is 
equivalent to ``Interchange Transaction'' in the NERC Reliability 
Standards Glossary of Terms. TVA suggests that ``scheduling intervals'' 
coincide with the ``ramp start'' times as defined in the Timing 
Requirements tables of the NERC Reliability Standards INT-005-3, 
Interchange Authority Distributes Arranged Interchange; INT-006-3, 
Response to Interchange Authority; and INT-008-3, Interchange Authority 
Distributes Status. TVA contends that to view the term ``scheduling 
interval'' otherwise would deviate from NERC Reliability Standards and 
potentially have an adverse effect on assessment periods for 
reliability.
    129. Bonneville Power requests that the Commission clarify the 
responsibilities of source and sink balancing authorities in regards to 
holding contingency reserves associated with scheduling of VER 
generation. Bonneville Power states that there is a debate regarding 
whether and when a source or sink balancing authority should deploy 
contingency reserves when a VER scheduling error exhausts the available 
balancing reserve capacity. Bonneville Power asks the Commission to 
clarify that a transmission provider can establish a base obligation to 
provide balancing reserve capacity to balance VERs and that the 
transmission provider can negotiate options for additional service 
beyond the base obligation with individual transmission customers.
    130. A few commenters request clarification of the appropriate 
curtailment priority for intra-hour transmission schedules under the 
proposed reform.\167\ Specifically, these commenters inquire as to 
whether a firm transmission reservation that is scheduled for less than 
the full hour would have priority over a non-firm hourly schedule. 
Bonneville Power and NRECA contend that submission of a firm intra-hour 
schedule should not necessarily result in the curtailment of lower 
priority hourly schedules. MidAmerican requests that the Commission 
clarify whether the submission of an intra-hour schedule by a 
transmission customer with firm transmission rights, after a competing 
intra-hour schedule from a transmission customer with only non-firm 
transmission rights, has curtailment priority.
---------------------------------------------------------------------------

    \167\ E.g., Bonneville Power; EEI; MidAmerican; NRECA.
---------------------------------------------------------------------------

    131. Other commenters question how ATC calculations should be 
performed after implementation of intra-hour scheduling.\168\ Public 
Interest Organizations state that current policy in the West does not 
allow ATC associated with transmission reservations that are not 
scheduled day-ahead to be used by other customers. Public Interest 
Organizations suggest that this policy may severely constrain or 
prohibit the effectiveness of intra-hour scheduling. In addition, 
Tacoma Power suggests that it may be appropriate to align ATC 
calculations with intra-hour scheduling intervals. Invenergy Wind 
asserts that the entire operational construct needs to shift from an 
hourly to a 15-minute basis in order to increase the efficiency of 
operating

[[Page 41506]]

the transmission system and acquiring sufficient reserves in order to 
integrate VERs on a non-discriminatory basis. However, NorthWestern 
argues that continued use of hourly transmission service reservations 
would not be inconsistent with implementation of intra-hour 
transmission scheduling, stating that administering intra-hour 
transmission reservations would be difficult and costly.
---------------------------------------------------------------------------

    \168\ E.g., Public Interest Organizations; Tacoma Power.
---------------------------------------------------------------------------

    132. Grant PUD makes reference to the Commission's use of the term 
``reasonable control'' in the Proposed Rule, where the Commission 
states that it is unduly discriminatory to continue to require a 
resource to match an hourly schedule, especially when the output of the 
resource fluctuates beyond its reasonable control.\169\ Grant PUD 
contends that what is reasonable depends on the current state of 
technology and requests that the Commission clarify that the definition 
of ``reasonable control'' is expected to improve over time.
---------------------------------------------------------------------------

    \169\ Grant PUD (citing Proposed Rule, FERC Stats. & Regs. ] 
32,664 at P 39).
---------------------------------------------------------------------------

ii. Commission Determination
    133. In response to Southern and EEI, the Commission clarifies that 
the term ``schedule'' as used in this Final Rule is equivalent to its 
use in Schedule 9 of the OATT: ``* * * a delivery schedule from [a] 
generator to (1) another Control Area or (2) a load within the 
Transmission Provider's Control Area.'' \170\ The procedures for 
submitting and revising a transmission schedule are delineated in 
sections 13.8 and 14.6 of the pro forma OATT, as changed by this Final 
Rule. Any transmission service schedule currently submitted pursuant to 
OATT sections 13.8 and 14.6 can therefore be modified or created in 15-
minute intervals under this Final Rule.
---------------------------------------------------------------------------

    \170\ OATT Schedule 9.
---------------------------------------------------------------------------

    134. In response to TVA, the Commission clarifies that the 15-
minute scheduling interval will be treated the same as the current one-
hour scheduling interval with respect to ramp start and stop times as 
defined in the Timing Requirements tables of NERC Reliability Standards 
INT-005-3, INT-006-3, and INT-008-3. As an example, in the Eastern 
Interconnection ramp start times will begin five minutes before the 
start of the 15-minute scheduling interval and end five minutes after 
the start of the 15-minute scheduling interval.
    135. Regarding responsibilities for holding contingency reserves, 
the Commission did not propose any changes to existing rules regarding 
the use of contingency reserves in this proceeding. As Bonneville Power 
notes, there is ongoing debate in the industry regarding when and how 
contingency reserves may be used under NERC Reliability Standards. The 
Commission concludes it is appropriate, in the first instance, for 
stakeholders to address these questions through the NERC 
processes.\171\
---------------------------------------------------------------------------

    \171\ The Commission addresses requests by Bonneville Power and 
others to limit the amount of capacity it must make available to 
transmission customers for generator regulation service under 
Schedule 10 in Sec.  IV.C.1 (Schedule 10--Generator Regulation and 
Frequency Response Service) below.
---------------------------------------------------------------------------

    136. The Commission also did not propose any changes to curtailment 
policies or ATC calculation. The Commission recognizes that 
transmission providers have flexibility under the pro forma OATT to 
award transmission service based on transmission capability that 
becomes available when firm transmission service is not scheduled by 
10:00 a.m. the day prior to operation.\172\ The Commission appreciates 
that, when a transmission provider makes service available under these 
circumstances, application of curtailment priorities and ATC 
calculation rules become more complicated. However, that is already the 
case under hourly transmission schedules. Therefore, the Commission did 
not propose any change to those practices to accommodate the 
possibility of intra-hour transmission schedules. All transmission 
schedules for firm service will continue to have curtailment priority 
over all transmission schedules for non-firm service \173\ and 
transmission providers will continue to be required to follow existing 
rules governing the calculation of ATC.\174\
---------------------------------------------------------------------------

    \172\ The pro forma OATT states that ``[s]chedules for the 
Transmission Customers' Firm Point-To-Point Transmission Service 
must be submitted no later than 10:00 a.m. * * * of the day prior to 
commencement of such service.'' OATT Schedule 13.8.
    \173\ The pro forma OATT makes clear that ``(p)arties requesting 
Non-Firm Point-To-Point Transmission Service for the transmission of 
firm power do so with the full realization that such service is 
subject to availability and to Curtailment or Interruption under the 
terms of the Tariff.'' OATT Schedule 14.5.
    \174\ In compliance with Order No. 890, public utility 
transmission providers have documented rules governing their 
calculation of ATC in Schedule C of their OATTs. See Order No. 890, 
FERC Stats. & Regs. ] 31,241 at P 193.
---------------------------------------------------------------------------

    137. In response to the request from Grant PUD for clarification of 
the term ``reasonable control,'' the Commission explains that use of 
the term ``reasonable control'' is not intended to be a metric or a 
determining factor, but illustrative of the difficulty VERs experience 
when attempting to follow hourly schedules accurately. The Commission 
does not find it necessary to offer any further clarification.
d. NERC and NAESB Standards
i. Commission Proposal
    138. In the Proposed Rule, the Commission noted that many 
commenters, in response to the NOI, claimed that shorter scheduling 
intervals may enhance reliability. The Commission therefore stated that 
it did not believe that an independent review of NERC Reliability 
Standards is necessary in order to propose implementation of intra-hour 
scheduling. However, the Commission sought comment on the issue to 
ensure that there is no inconsistency between relevant NERC standards 
and the proposed intra-hour scheduling tariff reform.\175\
---------------------------------------------------------------------------

    \175\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 37.
---------------------------------------------------------------------------

ii. Comments
    139. NERC states that certain entities currently offer 15-minute 
scheduling and that it is unaware of any conflicts with Reliability 
Standards. However, NERC asserts that wide spread use of intra-hour 
scheduling will likely require review and refinement of several 
existing Reliability Standards. Based on its preliminary review of 
Reliability Standards in coordination with industry stakeholders, NERC 
states that it does not believe there are any insurmountable hurdles 
that prevent industry from implementing 15-minute transmission 
scheduling. NERC explains that sufficient time must be allowed for 
Reliability Standards to be modified through the NERC Reliability 
Standards Committee prioritization process, but that transitioning to 
broad intra-hour scheduling flexibility is achievable in a reasonable 
timeframe.
    140. Some commenters do not anticipate that a review of NERC 
Reliability Standards is necessary to ensure reliability upon the 
implementation of intra-hour scheduling.\176\ NaturEner argues that an 
independent review of NERC standards may not be necessary, but if such 
a review occurs it should not delay implementation of intra-hour 
scheduling. Pacific Gas & Electric agrees that implementation of intra-
hour scheduling can be achieved without a review of NERC standards, but 
recommends that NERC and other industry experts review and update 
current planning and operating criteria to ensure that balancing 
authorities have the necessary tools to flexibly balance

[[Page 41507]]

loads and resources with the advent of increased VER penetration.
---------------------------------------------------------------------------

    \176\ E.g., NaturEner; Southern California Edison.
---------------------------------------------------------------------------

    141. Other commenters contend that review and modification of 
standards may be necessary, but not a prerequisite to 
implementation.\177\ Southern and Xcel state that only modest, if any, 
changes would be needed to NERC Reliability Standards. Southern 
indicates that several standards may need to be reviewed and revised as 
they currently contemplate hourly intervals. Xcel contends that 
standards related to the maximum lead times required for entry and 
approval of a schedule may require changes. Xcel explains that the lead 
times for entry and approval of a tag may exceed the length of a 
scheduling interval, thus diminishing the usefulness of intra-hour 
scheduling. AEP and Duke Energy suggest that sensitivity studies should 
be performed by an industry forum or working group to determine the 
reliability impacts of the proposed scheduling changes on real-time 
system operations.
---------------------------------------------------------------------------

    \177\ E.g., NERC; Pacific Gas & Electric.
---------------------------------------------------------------------------

    142. Several commenters argue that review and revision of NERC 
Reliability Standards, as well as NAESB business practice standards, 
may be necessary for the implementation of intra-hour scheduling at 15-
minute intervals.\178\ These commenters point out that many Reliability 
Standards and business practices are largely predicated on hourly 
scheduling intervals and govern transactions both internal to a 
particular balancing authority as well as across neighboring balancing 
authorities. Although most commenters did not identify specific changes 
to standards that would be necessary, some commenters suggest that NERC 
Reliability Standards related to some or all of the following areas be 
reviewed: Interchange Scheduling and Maintenance Coordination (INT), 
Resource and Demand Balancing (BAL), Emergency Preparedness and 
Operations (EOP), and Transmission Operations (TOP) standards.\179\ 
Additionally, commenters indicate that reliability scheduling tools, 
such as the Interchange Distribution Calculator used in the Eastern 
Interconnection and the WebSAS system used in the Western 
Interconnection for scheduling, curtailment and ``check out'' processes 
may also require modification.\180\
---------------------------------------------------------------------------

    \178\  E.g., Bonneville Power; Duke; EEI; MidAmerican; NRECA; 
PNW Parties; Southern.
    \179\ E.g., Duke; EEI; NERC; NRECA; PNW Parties; Southern.
    \180\ E.g., NERC; NRECA; Southern.
---------------------------------------------------------------------------

    143. NRECA cautions that any modifications to NERC standards should 
allow for the implementation of intra-hour scheduling but not mandate 
this practice. NRECA suggests that NERC be allowed to complete any 
updates to its standards associated with implementation of intra-hour 
scheduling prior to NAESB undertaking a review to ensure uniformity of 
approaches. NV Energy notes that, in order to schedule at 30 minute 
intervals or less, the protocols to effectuate such transactions must 
be agreed upon by all entities in WECC. Therefore, NV Energy requests 
that the Commission defer issuance of the Final Rule until the industry 
has had the opportunity to address NERC, WECC and NAESB standards 
issues.
    144. PNW Parties state that the Joint Initiative participants found 
it necessary to review NERC and NAESB standards as part of their 
development of a 30-minute scheduling program, but did not identify in 
comments whether any changes to standards or business practices were 
needed. PNW Parties suggests, however, that applicable standards and 
business practices be reviewed and revised as necessary prior-to 
implementing more granular scheduling.
    145. Some commenters within the VER industry request clarification 
and/or modification of NERC scheduling protocols to allow for a 
resource to be indentified as a ``sink.'' \181\ These commenters claim 
that this is necessary because under the Commission's proposed reforms 
VERs will be transacting on an intra-hour basis in order to supplement 
their variable supply. Iberdrola explains that, in order to enter into 
bilateral transactions for balancing energy where a VER's 15-minute 
schedule is less than its hour-ahead schedule, the additional balancing 
energy purchased from a generator with excess energy would need to be 
tagged as the ``source'' and the VER would need to be tagged as the 
``sink.'' Iberdrola claims that this is necessary because VERs will be 
transacting bilaterally in the sub-hourly timeframe in an effort to 
maintain the schedule that was entered prior to the operating hour. 
AWEA agrees, arguing that some of the benefits of intra-hour scheduling 
will not be realized without this additional clarification. In response 
to the potential concerns of transmission providers regarding 
generators being tagged as sinks, AWEA and Iberdrola argue that 
reliability concerns would only be present when the ultimate delivery 
point is unknown.\182\ AWEA explains that the case presented by a VER 
transacting as a sink for intra-hour scheduling purposes is entirely 
different, as the ultimate delivery point is already known. In this 
case, AWEA points out that there is a schedule to deliver energy to a 
real load and explains that this schedule is delivering energy to the 
load which the VER is unable to serve. Therefore, AWEA and Iberdrola 
conclude that such scheduling practices do not present reliability 
concerns.
---------------------------------------------------------------------------

    \181\ E.g., AWEA; Iberdrola.
    \182\ E.g., AWEA; Iberdrola.
---------------------------------------------------------------------------

iii. Commission Determination
    146. The Commission concludes that an independent review of NERC 
standards and NAESB business practices is not necessary prior to the 
implementation of intra-hour scheduling. As noted by NERC, several 
entities currently offer intra-hour scheduling without any apparent 
conflict with Reliability Standards. NERC comments that it does not 
believe there are any existing standards that prohibit industry from 
implementing intra-hour scheduling, and no commenters have pointed to 
specific NAESB business practices that prevent industry from 
implementing intra-hour scheduling. The Commission therefore concludes 
that it is not necessary to delay adoption of the intra-hour scheduling 
requirements of this Final Rule pending further review of NERC 
Reliability Standards and NAESB business practices. To the extent 
industry believes it is beneficial to refine one or more existing NERC 
Reliability Standards or NAESB business practices to reflect intra-hour 
scheduling, stakeholders can use existing processes to pursue such 
refinements.
    147. With regard to the requests from AWEA and Iberdrola to allow a 
VER resource to be designated as a ``sink'' for purposes of 
transmission scheduling, rules for scheduling transmission segments are 
set forth in NAESB's Coordinate Interchange Standards,\183\ which have 
been incorporated into the Commission's regulations by reference.\184\ 
The Proposed Rule did not propose any changes to those rules and the 
Commission declines to interpret the application to any particular 
transactions in this generic rulemaking proceeding.
---------------------------------------------------------------------------

    \183\ NAESB WEQ-004, App. C, Sec.  2 (Commercial Timing Table).
    \184\ See 18 CFR 38.2 (2011).
---------------------------------------------------------------------------

3. Other Issues
a. Comments
    148. Several commenters question the application of intra-hour 
scheduling reforms to HVDC transmission lines. Clean Line states that 
HVDC

[[Page 41508]]

transmission lines can precisely control power and, thus, are typically 
expected to submit schedules to public utility transmission providers. 
Clean Line requests that HVDC transmission lines receive equal 
treatment and be allowed to submit intra-hour schedules on the same 
basis as generators. In contrast, ALLETE and Midwest ISO Transmission 
Owners both request that the Commission grant an exemption from 15-
minute schedules for HVDC transmission lines. These commenters argue 
that 15-minute scheduling of HVDC transmission lines could lead to an 
increase in the duty on the load tap changers of HVDC converter 
transformers, potentially resulting in an increase in maintenance costs 
and an increased potential of transformer failure.
    149. Bonneville Power raises questions regarding the impact of 
intra-hour scheduling on dynamic scheduling practices. Bonneville Power 
states that 15-minute scheduling will lead to increased ramping and 
inhibit the availability of dynamic transfer capability in areas where 
dynamic transfer capability is limited, such as the Bonneville Power 
system and other parts of the West. Bonneville Power contends that 30-
minute scheduling relieves this problem and requests that the 
Commission gain a better understanding of the impacts that 15-minute 
scheduling will have on dynamic transfers. In contrast, First Wind 
requests that the Commission encourage dynamic transfers in addition to 
implementing intra-hour scheduling, suggesting that dynamic transfers 
can reduce regulation service requirements for transmission owners and 
transfer regulation requirements to purchasers of VER energy. First 
Wind also argues that intra-hour scheduling and dynamic transfers will 
allow for better tracking of real-time generation and reduce the need 
for ancillary services while increasing opportunities for flexible 
generation and demand response.
    150. M-S-R Public Power Agency states that shortening the 
scheduling interval does not reduce the intermittency of the VERs 
themselves. M-S-R Public Power Agency offers that as a matter of 
physics a VER requires a back-up resource to ``balance'' its 
intermittency, irrespective of scheduling, adding that while a shorter 
scheduling interval may mitigate the number of megawatts needed to 
assure reliability, it will not mitigate the location or cost of back-
up reserves. M-S-R Public Power Agency goes on to state that VER 
penetration levels of 20-25 percent start to exhaust the capability of 
even the most robust systems and that the proposed mitigation may be 
insufficient. M-S-R Public Power Agency explains that the raw energy of 
VERs must be converted to conditioned energy (traditional resources) at 
the source, and not shifted to other locations through mitigation, or 
there will be a degradation of services to all VERs within that system. 
M-S-R Public Power Agency states that intermittent resources require 
that the transmission owner have nearly infinite capability to provide 
backup resources; however, even the most robust balancing authority has 
limitations of how fast, how often, and when it can provide back up 
resources. M-S-R Public Power Agency offers that, with both the cost of 
transmission and reliability (back-up generation) challenges, VERs may 
be uneconomic. M-S-R Public Power Agency encourages the Commission to 
solicit input on this issue.

Commission Determination

    151. All transmission customers that are currently eligible to 
submit hourly energy schedules will be eligible to participate in 
intra-hour scheduling, including HVDC lines that currently submit 
hourly energy schedules. To the extent a transmission provider believes 
an exemption is appropriate, it has the right to request a waiver of 
all or part of the OATT requirements as described in 18 CFR 35.28(d): 
``A public utility subject to the requirements of this section and 
Order No. 889, FERC Stats. & Regs. ]31,037 (Final Rule on Open Access 
Same-Time Information System and Standards of Conduct) may file a 
request for waiver of all or part of the requirements of this section, 
or Part 37 (Open Access Same-Time Information System and Standards of 
Conduct for Public Utilities), for good cause shown.'' Waiver requests 
will be evaluated in separate proceedings if and when they are 
submitted based on the facts and circumstances of each request.
    152. With regard to the use of dynamic schedules, the Commission 
did not propose and is not adopting any change in policy with regard to 
dynamic scheduling. The Commission is not persuaded by arguments from 
Bonneville Power that 15-minute scheduling intervals will negatively 
affect dynamic transfer capability. However, the Commission 
acknowledges that a transmission provider's implementation of charges 
for generator regulation service, as discussed in the following 
section, may have the result of encouraging the use of dynamic 
scheduling to avoid such charges.
    153. In response to M-S-R Public Power Agency, the Commission 
appreciates that the location of a particular resource can be relevant 
in determining whether it can be used to satisfy reserve obligations. 
That is, a public utility transmission provider providing ancillary 
services under the pro forma OATT, or a transmission customer self-
supplying such ancillary services needs transmission capacity to ensure 
deliverability of a particular resource. Whether that is the case will 
be fact specific and we expect the transmission provider to take the 
appropriate steps to ensure such transmission capacity is available.

B. Data Reporting To Support Power Production Forecasting

    154. The second of the two reforms adopted in this Final Rule 
relates to the submission of meteorological and forced outage 
data,\185\ by new interconnection customers whose generating facilities 
are VERs, to the public utility transmission provider with which the 
customer is interconnected if the public utility transmission provider 
is doing power production forecasting. As discussed below, the 
Commission amends the pro forma LGIA to effectuate this data reporting 
requirement. The Commission concludes that, without these reporting 
requirements in place, 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.
---------------------------------------------------------------------------

    \185\ The Proposed Rule used the term ``operational data'' and 
specified forced outages as a particular type of operational data. 
To reflect the limited nature of data to be reported under this 
Final Rule more accurately, the Commission instead refers more 
specifically to ``forced outage data'' in our determinations here 
and accompanying revisions to the pro forma LGIA. We also note that 
Section 9.7.1 of the LGIA requires Transmission Providers and 
Interconnection Customers to coordinate and report planned outages. 
Within the context of this Final Rule, the Commission references the 
term ``forced outage'' as defined by NERC. See NERC Glossary of 
terms available at https://www.nerc.com/files/Glossary_of_Terms.pdf.
---------------------------------------------------------------------------

1. Data Requirements
a. Commission Proposal
    155. To facilitate the development and deployment of power 
production forecasting by public utility transmission providers, the 
Proposed Rule set forth revisions to the pro forma LGIA that would 
require interconnection customers whose generating facilities are VERs 
to provide certain meteorological and operational data to the public 
utility transmission provider with whom they are

[[Page 41509]]

interconnected, if doing forecasting. The Commission proposed that such 
data would be transmitted from the interconnection customer to the 
public utility transmission provider at or near real-time. The 
Commission stated that this proposal built on existing Commission data-
sharing requirements by outlining specific meteorological and 
operational data necessary to develop power production forecasts.\186\
---------------------------------------------------------------------------

    \186\ See Proposed Rule, FERC Stats. & Regs. ] 32,664 at PP 60-
61.
---------------------------------------------------------------------------

    156. With regard to the reporting of meteorological data, the 
Commission proposed revisions to the pro forma LGIA that would result 
in different types of meteorological information being provided by 
interconnection customers based on the type of VER they own and/or 
operate. The Commission proposed to require interconnection customers 
whose generating facilities are wind-based VERs to provide public 
utility transmission providers with site-specific meteorological data 
including, but not limited to, temperature, wind speed, wind direction, 
and atmospheric pressure. The Commission proposed to require 
interconnection customers whose generating facilities are solar-based 
VERs to provide public utility transmission providers with site-
specific meteorological data including, but not limited to, 
temperature, atmospheric pressure, and cloud cover. The Commission 
recognized that different power production forecasts may require 
meteorological instruments to be located at hub height, up-wind of 
resources, or at ground level. However, the Commission refrained from 
proposing specific requirements in this respect and, instead, proposed 
to allow the public utility transmission provider and interconnection 
customers to negotiate these details taking into account the size and 
configuration of the VER facility, its characteristics, location, and 
importance in maintaining generation resource adequacy and transmission 
system reliability in its area. The Commission stated that resource-
specific data requirements contained in individual LGIAs must be 
negotiated on a not unduly discriminatory basis.\187\
---------------------------------------------------------------------------

    \187\ See id. P 61.
---------------------------------------------------------------------------

    157. With respect to the reporting of operational data, the 
Commission proposed to revise the pro forma LGIA to require 
interconnection customers whose generating facilities are VERs to 
report to the public utility transmission provider any forced outages 
that reduce the generating capability of the resource by 1 MW or more 
for 15 minutes or more. The Commission noted that provision of VER 
outage data at this level of granularity would allow a public utility 
transmission provider to ascertain the extent to which current VER 
power production is a result of unit availability as opposed to 
changing weather conditions.\188\ The Commission preliminarily found 
that having such information would eliminate a significant source of 
forecasting errors by ensuring that the public utility transmission 
provider has accurate information regarding the capacity actually 
available to produce electricity during the time-frame of the 
operational forecasts.\189\
---------------------------------------------------------------------------

    \188\ See id. P 62 (citing Cal. Indep. Sys. Operator Corp., 131 
FERC ] 61,087, at P 64 (2010)).
    \189\ Id. P 62.
---------------------------------------------------------------------------

    158. The Commission sought comment on the extent to which the lists 
of basic meteorological and operational data articulated above may be 
inadequate or incomplete in achieving the stated power production 
forecasting goals.\190\
---------------------------------------------------------------------------

    \190\ Id. P 63.
---------------------------------------------------------------------------

b. Comments
    159. Commenters addressing the reporting of meteorological data 
generally support requiring the provision of data as necessary to 
enable public utility transmission providers to employ power production 
forecasts.\191\ While disagreeing that public utility transmission 
providers should be responsible for power production forecasting, 
Montana PSC argues that, should the Commission impose forecasting 
requirements, public utility transmission providers should have access 
to all meteorological data that are site-specific to the VER, provided 
that the parties have a confidentiality agreement in place to protect 
proprietary information. BP Companies and First Wind request that the 
Commission clarify that the proposal is only relevant to instances in 
which the public utility transmission provider is developing and/or 
implementing VER power production forecasting.
---------------------------------------------------------------------------

    \191\ E.g., AWEA; Bonneville Power; California ISO; CEERT; Clean 
Line; California PUC; Exelon; First Wind; Iberdrola; Independent 
Energy Producers; Independent Power Producers Coalition-West; ISO/
RTO Council; ISO New England; Large Public Power; Midwest ISO; 
Midwest ISO Transmission Owners; NaturEner; NextEra; NRECA; Pacific 
Gas & Electric; PJM; Powerex.
---------------------------------------------------------------------------

    160. Several commenters support the Commission's identification of 
certain categories of meteorological data to be provided by wind and 
solar resources.\192\ For example, with regard to wind resources, 
Iberdrola agrees that wind speed, wind direction, temperature and 
pressure are all key atmospheric variables related to wind farm output 
and are the most important fields to measure. With regard to solar 
resources, NextEra, SEIA, and Xcel generally support the minimum 
categories of data identified in the Proposed Rule, but they suggest 
that the Commission revise the reference to cloud cover because it is 
ambiguous. Specifically, NextEra and SEIA recommend that the Commission 
require solar resources to report diffuse, direct, and global 
horizontal irradiance. NextEra adds that humidity should also be 
provided for a solar VER using concentrating thermal solar technology, 
while SEIA suggests that plane of array irradiance or direct normal 
radiation may also be necessary. These commenters note that irradiance 
is often a better measure because it actually drives energy production.
---------------------------------------------------------------------------

    \192\ E.g., AWEA; Iberdrola; ISO New England; RENEW.
---------------------------------------------------------------------------

    161. Commenters generally support the Commission's proposal to 
allow the public utility transmission provider and interconnection 
customer to negotiate additional meteorological and operational data 
reporting requirements.\193\ Commenters identified a variety of 
additional meteorological and facility-specific data that may be useful 
in developing and deploying power production forecasts. These 
commenters generally note that regional differences may dictate 
additional data needs,\194\ with several asking the Commission to 
acknowledge that additional data beyond that specifically identified in 
the Proposed Rule may be needed by a public utility transmission 
provider.\195\
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    \193\ E.g., Bonneville Power; ISO New England; ISO/RTO Council; 
Large Public Power Council; Midwest ISO; NRECA; PNW Parties; RENEW; 
Xcel.
    \194\ E.g., Bonneville Power; First Energy; ISO New England; 
ISO/RTO Council; NextEra; MidAmerican; Midwest ISO; Midwest ISO 
Transmission Owners; NorthWestern; NRECA; Pacific Gas & Electric; 
Xcel.
    \195\ E.g., Bonneville Power; ISO New England; Midwest ISO; 
NextEra; NRECA.
---------------------------------------------------------------------------

    162. Several commenters raise concerns regarding the Commission's 
discussion of the location of meteorological towers and other equipment 
necessary to record and report data to public utility transmission 
providers.\196\ NextEra asks that the Commission refrain from allowing 
public utility transmission providers to require VERs to install 
multiple meteorological towers, arguing that data beyond what is 
available through one meteorological tower has little value for 
advanced power production forecasting methods. Invenergy similarly 
argues that a single meteorological tower per

[[Page 41510]]

facility is usually sufficient for predicting plant output.
---------------------------------------------------------------------------

    \196\ E.g., AWEA; Invenergy; NextEra.
---------------------------------------------------------------------------

    163. With regard to the frequency of reporting meteorological data, 
several commenters suggest that the frequency of data reporting should 
match the use of the data, which may not be at or near real-time.\197\ 
For example, AWEA, Iberdrola, and NextEra state that second-by-second 
or minute-by-minute meteorological recordings yield minimal benefits 
for forecasting accuracy and could be costly and burdensome. AWEA and 
Clean Line suggest that a reasonable requirement for the frequency at 
which real-time meteorological and operational data is reported from a 
wind plant is 10 minutes or more. NorthWestern, however, states that it 
would be helpful to require each VER to update the forecasting data 
that it has provided to the public utility transmission provider when 
it provides a new energy schedule.
---------------------------------------------------------------------------

    \197\ E.g., AWEA; Clean Line; Iberdrola; NextEra; NaturEner; 
NorthWestern; Public Interest Organizations.
---------------------------------------------------------------------------

    164. AWEA and Iberdrola also contend that distinctions should be 
made between the types of data that should be provided in real-time and 
the types of data that should be provided historically. These 
commenters state that archived time series data are crucial to 
statistical forecasting techniques and that this application is not 
done in real-time. AWEA and Iberdrola state that data needed for 
forecast training can be compiled into larger datasets and transmitted 
at less frequent intervals at a much lower cost. RenewElec and 
Bonneville Power generally agree that there is significant value in 
historical data recorded by VERs.
    165. With regard to the operational data reporting requirements, 
some commenters urge the Commission to adopt the proposed requirement 
that VERs report to the public utility transmission provider any forced 
outages that reduce the generating capacity of a resource by 1 MW or 
more for 15 minutes or more.\198\ For example, Bonneville Power states 
that having access to forced outage information will enable public 
utility transmission providers to determine whether forecast inaccuracy 
results from unit availability, changing weather conditions, or a 
combination of the two. Bonneville Power further states that without 
such information it will be difficult to verify forecasts and improve 
forecast accuracy. California ISO requests that the Commission not 
overturn its recent decision approving California ISO's 1 MW threshold 
for reporting a forced outage of an eligible intermittent resource. 
California ISO argues that outage reporting requirements that are less 
stringent than those proposed would increase the likelihood that the 
forecasting algorithm would accumulate inaccurate data.
---------------------------------------------------------------------------

    \198\ E.g., Bonneville Power; California ISO; NRECA.
---------------------------------------------------------------------------

    166. Other commenters acknowledge that forced outage data are 
useful in developing power production forecasts, but disagree on the 
exact reporting requirements.\199\ Some commenters contend that a 1 MW 
reporting threshold would pose an unnecessary burden on a wind plant 
owner/operator, yield minimal benefits for forecast accuracy, and pose 
compliance difficulties.\200\ Instead of the proposed requirement, 
NaturEner recommends requiring that only planned outages of greater 
than 15 percent of the generator's capacity should be reported as soon 
as they are known by the generator. AWEA suggests that reporting apply 
only to forced outages that exceed 10 percent of the nameplate capacity 
of a plant, a requirement that AWEA states is similar to the one 
imposed on conventional generators. NextEra similarly asks that the 
outage reporting requirements be identical to those that apply to 
conventional resources. MidAmerican recommends that VER transmission 
customers be required to report forced outages lasting more than 24 
hours and involving the lesser of either 20 MW or 50 percent of 
nameplate capacity. Xcel recommends that the Commission ask NERC to 
analyze and determine the appropriate threshold level for reporting VER 
outages to public utility transmission providers and balancing 
authorities.
---------------------------------------------------------------------------

    \199\ E.g., AWEA; Exelon; NaturEner; SEIA; Xcel; MidAmerican; 
NextEra.
    \200\ E.g., AWEA; Iberdrola; NaturEner; MidAmerican; PJM.
---------------------------------------------------------------------------

    167. SEIA contends that the forced outage reporting requirement may 
be appropriate for large solar photovoltaic generators, but not for 
concentrating solar plants that experience frequent changes in power 
output. SEIA states that, with respect to concentrating solar power-
generating facilities, the Commission should consider a threshold for 
reporting such fluctuations based either on the total capacity of the 
facility or particular types of maintenance or repair activities that 
would result in an outage at a percentage of the facility.
    168. Exelon asks the Commission to clarify what constitutes a 
forced outage for purposes of the requirement to report operational 
data, suggesting it should only include unanticipated outage events. 
NRECA notes that the Proposed Rule did not identify the frequency for 
reporting operational data to the public utility transmission provider. 
NRECA contends that the public utility transmission provider should be 
notified as soon as the VER is aware of an outage.
    169. Several commenters recommend that the Commission provide 
regional flexibility with respect to the operational data reporting 
requirements.\201\ For example, Iberdrola states that VER forced outage 
reporting requirements should be regional and: (1) Based on the 
penetration of VERs in the region; (2) based on the ability of the 
transmission provider to incorporate the data into power production 
forecasting from VERs that is in turn used for reliably operating the 
system; and (3) limited to an interval that enables the use of 
predictive outage reporting capability.
---------------------------------------------------------------------------

    \201\ E.g., Iberdrola; ISO New England; Midwest ISO Transmission 
Owners; PJM; Southern California Edison.
---------------------------------------------------------------------------

    170. Some commenters argue that the Commission should acknowledge 
the importance of standardized regional reporting mechanisms when 
considering these proposed reforms.\202\ For example, Midwest ISO notes 
that IEC Standard 61400-25 already exists to facilitate the exchange of 
information between individual wind turbines, their constituent 
components, wind power plants, area control, and other external 
systems. Midwest ISO suggests that use of a common format for 
communicating data between the VER and public utility transmission 
provider would promote the development of power production forecasting. 
However, Invenergy asks that the Commission make clear that public 
utility transmission providers are required to accept reasonable 
alternative means of data communication and not implement uniform 
standards that impose unnecessary costs on wind projects.
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    \202\ E.g., Alstom; EEI; Midwest ISO.
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c. Commission Determination
    171. The Commission adopts, as modified below, the proposed 
requirement that interconnection customers whose generating facilities 
are VERs 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. As 
discussed below, power production forecasting can be used by public 
utility transmission providers to operate their

[[Page 41511]]

systems and manage reserves more efficiently. To the extent a public 
utility transmission provider seeks to rely on power production 
forecasting, the Commission concludes it is appropriate to require new 
interconnection customers whose generating facilities are VERs to 
provide related data to the public utility transmission provider under 
the circumstances below. The Commission therefore directs public 
utility transmission providers to modify their pro forma LGIAs to 
effectuate the data reporting requirement.
    172. As the Commission noted in the Proposed Rule, industry studies 
demonstrate the potential for significant benefits from the 
incorporation of power production forecasts into scheduling and unit 
commitment processes. In WECC alone, NREL estimated the use of VER 
power production forecasts has the potential to reduce operating costs 
by up to 14 percent or $5 billion per year.\203\ NERC has similarly 
concluded that forecasting the output of variable generation is 
critical to bulk power system reliability in order to ensure that 
adequate resources are available for ancillary services and ramping 
requirements.\204\ NERC has therefore recommended that forecasting 
techniques be incorporated into day-to-day operational planning and 
real-time operations routines/practices including unit commitment and 
dispatch.\205\ The Commission notes that the benefits of power 
production forecasting can accrue across a variety of time frames, 
including the operating day, day-ahead, and seasonally.
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    \203\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 45 
(citing National Renewable Energy Laboratory, Western Wind and Solar 
Integration Study ES-18 (2010), available at https://www.nrel.gov/wind/systemsintegration/wwsis.html).
    \204\ NERC, Accommodating High Levels of Variable Generation 54 
(2009), available at https://www.nerc.com/files/IVGTF_Report_041609.pdf.
    \205\ Id. at 59.
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    173. However, power production forecasts are only as good as the 
data on which they rely. The ability of public utility transmission 
providers to use power production forecasting in the commitment and de-
commitment of resources may be limited without adequate meteorological 
and forced outage data from VERs. The current lack of meteorological 
and forced outage data reporting requirements in the pro forma LGIA 
therefore may limit efforts by public utility transmission providers 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. The Commission remedies this deficiency by 
adopting reporting requirements for new interconnection customers whose 
facilities are VERs, commensurate with the power production forecasting 
employed by the public utility transmission provider, to allow for more 
accurate commitment and de-commitment of resources providing reserves, 
ensuring that reserve-related charges imposed on customers remain just 
and reasonable and not unduly discriminatory or preferential. The 
Commission implements this requirement by requiring public utility 
transmission providers to modify their pro forma LGIAs to include the 
reporting requirements discussed below.
    174. The reporting requirements adopted in this Final Rule are 
specifically designed to support the development and deployment of 
power production forecasting by public utility transmission providers. 
As a result, nothing in this Final Rule should be construed as creating 
an obligation for interconnection customers whose generating facilities 
are VERs to provide meteorological and forced outage data in cases 
where the public utility transmission provider is not engaging in power 
production forecasting. The Commission recognizes that VER potential 
and penetration varies across public utility transmission provider 
systems and that, at this time, not all public utility transmission 
providers have sufficient levels of VERs to warrant engaging in power 
production forecasting. The Commission is nonetheless amending the pro 
forma LGIA to ensure that those public utility transmission providers 
seeking to develop and deploy power production forecasting in response 
to increasing VER penetration have adequate information to do so. To 
make the conditional nature of the reporting requirements clear, the 
Commission revises the proposed Article 8.4 of the pro forma LGIA to 
state that all requirements for meteorological and forced outage data 
must be consistent with the power production forecasting employed by 
the Transmission Provider, if any, to manage reserve commitments. The 
Commission believes that this strikes a reasonable balance between the 
requirement to provide the data and the public utility transmission 
provider's use of the data to manage reserve commitments more 
efficiently.
    175. Turning to the particular reporting requirements imposed on 
interconnection customers whose generating facilities are VERs, the 
Commission affirms the approach set forth in the Proposed Rule allowing 
public utility transmission providers flexibility in identifying the 
specific meteorological and forced outage data to be reported. As 
proposed, Article 8.4 of the pro forma LGIA would specify certain 
categories of data to be provided by interconnection customers with 
VERs having wind or solar as the energy source, with the exact 
specifications of data to be provided taking into account the size and 
configuration of the VER, its characteristics, location, and its 
importance in maintaining generation resource adequacy and transmission 
system reliability in its area. Some commenters generally support this 
approach, stating that the type of power production forecasting 
deployed by public utility transmission providers and the tools used to 
perform forecasts could vary widely, and therefore any reporting 
requirements associated with power production forecasting should be 
flexible.\206\ This approach will provide public utility transmission 
providers the flexibility to negotiate, in the first instance, with 
interconnection customers whose generating facilities are VERs to 
identify the particular data to be reported by the customer.
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    \206\ E.g., Iberdrola; NextEra.
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    176. The Commission finds that this flexible approach to 
establishing data reporting requirements will ensure that all reporting 
of meteorological and forced outage data corresponds with the power 
production forecasting being employed by the public utility 
transmission providers. To be clear, however, public utility 
transmission providers cannot unduly discriminate among interconnection 
customers with regard to data reporting requirements. By linking the 
requirement to provide meteorological and forced outage data to the use 
of these data by the public utility transmission provider in power 
production forecasting to manage reserve commitments, the Commission 
seeks to minimize opportunities for undue discrimination as well as 
needless burden on interconnection customers. At the same time, to the 
extent meteorological and forced outage data are needed for the public 
utility transmission provider to engage in power production 
forecasting, they must be provided by the interconnection customer, 
even if that means investment in additional equipment by the 
customer.\207\ To the extent there are

[[Page 41512]]

concerns of discriminatory or unnecessary application of data reporting 
requirements, interconnection customers can request that the public 
utility transmission provider file with the Commission an unexecuted 
LGIA in order to resolve the disagreement.\208\
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    \207\ The Commission acknowledges the concern of some commenters 
that the installation of multiple meteorological towers would 
increase costs for an interconnection customer. Whether data from a 
single meteorological tower is sufficient to support the power 
production forecasting deployed by the public utility transmission 
provider should be addressed as part of the negotiation of the LGIA.
    \208\ See 16 U.S.C. 824d (2006); 18 CFR 35.13 (2010).
---------------------------------------------------------------------------

    177. Notwithstanding the flexibility provided for party-specific 
negotiations of data reporting requirements, the record in this 
proceeding also confirms that some categories of meteorological data 
from VERs having wind or solar as the energy source will be relevant to 
most, if not all, power production forecasting deployed by a public 
utility transmission provider for these resources. Therefore, the 
Commission adopts the proposal to require certain categories of 
meteorological data from VERs having wind or solar as the energy 
source. Specifically, an interconnection customer with a VER having 
wind as the energy source must provide, at a minimum, site-specific 
meteorological data including: Temperature, wind speed, wind direction, 
and atmospheric pressure. An interconnection customer with a VER having 
solar as the energy source must provide, at a minimum, site-specific 
meteorological data including: temperature, atmospheric pressure, and 
irradiance. The exact specifications of data to be provided by the 
interconnection customer will remain subject to negotiation between the 
parties, which as noted above must take into account the size and 
configuration of the VER, its characteristics, location, and its 
importance in maintaining generation resource adequacy and transmission 
system reliability in its area. It may also include additional 
meteorological data commensurate with the power production forecasting 
employed by the public utility transmission provider. As with other 
data reporting requirements, the public utility transmission provider 
may file an unexecuted LGIA pursuant to FPA section 205 seeking to 
demonstrate the necessity of requests for additional information if the 
parties cannot reach mutual agreement as to the specifications of data 
to be provided.\209\
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    \209\ Id.
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    178. By defining certain categories of data that must be provided, 
while leaving the exact specifications of data to negotiation between 
the interconnection customer and the public utility transmission 
provider, the Commission has sought to balance the competing interests 
of clarity and flexibility. The Commission appreciates that defining 
all data requirements with precision in this Final Rule might result in 
rules that are easier to implement. However, it also could lead to 
interconnection customers incurring costs to provide data at a level of 
granularity, for example, that is of no use to the public utility 
transmission provider given the type of power production forecasting 
deployed. By linking the reporting requirements to the data needs of 
the public utility transmission provider, the Commission seeks to 
facilitate the deployment of power production forecasting without 
unduly burdening the interconnection customer.
    179. In the Proposed Rule, the Commission included ``cloud cover'' 
within the categories of data required of interconnection customers 
with a VER having solar as the energy source. The Commission agrees 
with commenters that the term ``cloud cover'' is imprecise and thus we 
modify Article 8.4 of the pro forma LGIA to refer to ``irradiance.'' 
However, the Commission declines to distinguish between types of 
irradiance and also declines to include ``humidity'' in the minimal 
categories of data. These additional characteristics may be more 
relevant for some types of facilities than others, so we leave to 
public utility transmission providers and their interconnection 
customers to identify the specifications of data relevant for 
reporting.
    180. With regard to the frequency and timing of data reporting, the 
Commission modifies the Proposed Rule and allows public utility 
transmission providers and interconnection customers whose generating 
facilities are VERs to negotiate the frequency and timing of data 
submittals. The Proposed Rule would have required the reporting of data 
at or near real-time. In response, commenters such as AWEA and 
Iberdrola note that some power production forecasts use archived time 
series data that may be compiled and transmitted to public utility 
transmission providers at a significant costs savings when compared to 
the ongoing reporting of data at or near real-time, whereas 
NorthWestern suggests that data could be provided on a ten-minute or 
longer basis. Based on comments received, the Commission concludes it 
is more appropriate for the frequency and timing data submittals to be 
negotiated by the parties to ensure that the reporting of data is 
consistent with the type of power production forecasting being deployed 
by the public utility transmission provider. The Commission revises 
Article 8.4 of the pro forma LGIA accordingly.
    181. In the Proposed Rule, the Commission sought to require the 
reporting of forced outages of 1 MW or more for 15 minutes or more. In 
response, commenters disagree as to the relevant level of granularity 
for outage data. Rather than establish a specific megawatt reporting 
threshold or frequency that could result in the reporting of data that 
are not used by the public utility transmission provider, the 
Commission concludes it is more appropriate for the public utility 
transmission provider and interconnection customer to negotiate the 
exact specifications of forced outage data to be provided, taking into 
account the size and configuration of the VER, its characteristics, 
location, and its importance in maintaining generation resource 
adequacy and transmission system reliability in its area. As noted in 
the Proposed Rule, this will provide the flexibility necessary to 
ensure that the reporting of forced outage data is commensurate with 
the power production forecasting being employed by the public utility 
transmission provider, consistent with any regional practices that may 
exist. Therefore, the Commission modifies the Proposed Rule to align 
the reporting of forced outages with the power production forecasting 
being employed by the public utility transmission provider. The 
Commission also declines to adopt alternative minimum thresholds or 
pre-define forced outages for purposes of reporting requirements as 
requested by some commenters.
    182. Some commenters request that the Commission standardize 
protocols for reporting meteorological or forced outage data required 
by this Final Rule. The Proposed Rule did not contain standard 
protocols for data reporting and, as a result, the merits of such a 
requirement have not been fully addressed in the record. Whether 
standardization of data communications would facilitate or hinder 
development of power production forecasting may implicate a variety of 
data and communications issues that would benefit from broad industry 
input through standards development processes such as those used by 
NAESB and other organizations.
d. LGIA
    183. In order to effectuate the reporting requirements discussed 
above, the Proposed Rule set forth amendments to the pro forma LGIA 
adding a new section Article 8.4, Provision of Data from a Variable 
Energy Resource.

[[Page 41513]]

Consistent with the approach of Order Nos. 2003 and 661,\210\ the 
Commission proposed not to require retroactive changes to LGIAs that 
are already in effect. However, the Commission sought comment as to 
whether this approach would prevent public utility transmission 
providers from effectively implementing power production 
forecasting.\211\ The Commission also preliminarily found that the pro 
forma LGIA includes adequate confidentiality protections for sensitive 
data obtained from VERs.\212\
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    \210\ Order No. 661, FERC Stats. & Regs. ] 31,186 at P 120; 
Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 910.
    \211\ See Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 64.
    \212\ Id. P 60 (citing Pro Forma LGIA Article 22, which sets 
forth the confidentiality provisions applicable to data exchanged 
through the interconnection process).
---------------------------------------------------------------------------

    184. The Commission noted that it was proposing revisions only to 
interconnection customers whose generating facilities are VERs greater 
than 20 MW and, as a result, proposing revisions only to the pro forma 
LGIA and not the pro forma Small Generator Interconnection Agreement 
(SGIA). The Commission sought comment on whether the proposed reforms 
should also apply to interconnection customers whose generating 
facilities are VERs of 20 MW or less, so as to require revisions to the 
pro forma SGIA.
e. Comments
    185. The Commission received a variety of comments on its proposal 
to not require retroactive changes to LGIAs that are in effect. 
NaturEner argues that without data from existing resources, power 
production forecasts would be less reliable or robust, resulting in 
artificially high required reserves and attendant expenses. AWEA, Clean 
Line, and Iberdrola state that they would not oppose requiring data 
from resources that have executed an LGIA, provided that the 
interconnection customers are only required to report data that are 
currently gathered by the VER. AWEA explains that data already are 
being collected by many wind plants deployed since 2005 and that many 
public utility transmission providers have already imposed reporting 
requirements. However, Southern MN Municipal asserts that the proposed 
reforms should not be extended to resources that have already executed 
an interconnection agreement. Bonneville Power asserts that Articles 
9.3 and 9.4 of the LGIA give the transmission provider a unilateral 
right to update its instructions and operating protocols and procedures 
regardless of whether the proposed Article 8.4 is applied 
retroactively.
    186. Midwest ISO Transmission Owners request that the Commission 
address the circumstances under which a VER with an existing 
interconnection agreement might become subject to the new power 
production forecasting requirement if it is applied prospectively. 
Midwest ISO Transmission Owners state that, at the very least, any 
increase in a facility's generating capacity or material modification 
that would necessitate a new LGIA should be sufficient to subject the 
VER generator to the new power production forecasting-related data 
requirements under the applicable tariff.
    187. Some commenters suggest implementing reporting requirements 
for meteorological and forced outage data through the pro forma OATT in 
order to impose those requirements on existing resources or otherwise 
allow for changes in reporting requirements over time.\213\ AWEA 
contends that, if the Commission determines to apply the reporting 
requirements to existing resources, it would be more appropriate to 
place the requirements in the pro forma OATT. Sunflower and Mid-Kansas 
agree, noting that the pro forma LGIA already requires parties to 
operate their facilities consistent with Applicable Laws and 
Regulations, including OATT requirements. Large Public Power argues 
that it is important that all VERs provide the operational information 
required by a transmission provider and, therefore, also recommends 
placing reporting requirements in the transmission tariff. Southern 
California Edison contends that placing reporting requirements in the 
pro forma OATT would allow greater flexibility in structuring 
agreements by referencing requirements in the California ISO Tariff, as 
they may change from time to time.
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    \213\ E.g., AWEA; Large Public Power; Southern California 
Edison; Sunflower and Mid-Kansas.
---------------------------------------------------------------------------

    188. Other commenters ask the Commission to allow reporting 
requirements to be stated in market rules or business practices.\214\ 
ISO New England requests that the Commission afford flexibility for 
public utility transmission providers to determine the mechanism by 
which to collect the required VER data. National Grid states that 
rather than requiring a proscriptive amendment of the pro forma LGIA, 
the Commission should require each region to work with its stakeholders 
to develop appropriate methods for forecasting the energy output from 
VERs. Pacific Gas & Electric requests that in its Final Rule the 
Commission provide latitude for the California ISO and other similarly-
situated transmission providers to continue their existing programs for 
gathering relevant meteorological and operational data, and proposing 
incremental refinements to them, so long as they conform to the 
purposes of the Final Rule. Xcel similarly argues that the specific 
data requirements for individual public utility transmission providers 
should be identified through a business practice or other OASIS posting 
to allow adjustments due to changing system operating needs, 
improvements in meteorological forecasting technologies, or 
modifications in NERC reliability requirements.
---------------------------------------------------------------------------

    \214\ E.g., California PUC; Dominion; ISO New England; National 
Grid; Pacific Gas & Electric.
---------------------------------------------------------------------------

    189. With regard to the Commission's question as to whether the pro 
forma SGIA needs to be revised, many parties argue that the provision 
of data under the SGIA may be appropriate in some instances.\215\ PJM 
and Snohomish County PUD note that the costs of reporting the proposed 
data to public utility transmission providers by small VERs could be 
higher than for larger resources. As such, they argue that the 
Commission should carefully consider these costs when applying 
reporting requirements. Several other commenters acknowledge 
difficulties associated with gathering data from resources subject to 
the SGIA, and propose a variety of thresholds to determine whether 
reporting requirements should apply to the resource.\216\ For example, 
AWEA states that it makes sense to apply similar data reporting 
requirements to smaller-scale generators where it can be demonstrated 
that the data will be used for improving VER forecast accuracy and that 
the benefits exceed the cost of data collection. Others state that 
small resources should use alternative reporting requirements.\217\ 
Southern California Edison recommends that the Commission consider an 
approach that aggregates individual site data from small generators in 
a geographic area, which reduces cost impacts to smaller projects.
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    \215\ E.g., California ISO; EEI; Duke; ISO New England; 
MidAmerican; NRECA; Pacific Gas & Electric; PNW Parties; Snohomish 
County PUD; Southern California Edison; Tacoma Power; Xcel.
    \216\ E.g., AWEA; RenewElec; SEIA; Tacoma Power; Xcel.
    \217\ E.g., Alstom Grid; RENEW.
---------------------------------------------------------------------------

    190. Commenters contend that the public utility transmission 
provider should have the flexibility to identify and require data from 
small

[[Page 41514]]

generators.\218\ For example, Bonneville Power argues that the 
Commission should require small VERs to provide meteorological and 
operational data according to the requirements established by their 
public utility transmission provider. These commenters generally agree 
that public utility transmission providers may have different 
forecasting needs, and that they require flexibility to address such 
issues. NextEra argues that there is no convincing reason to limit the 
forecasting requirement to resources larger than 20 MW, and that the 
impact of small VERs on system variability is the same as resources 
greater than 20 MW. Midwest ISO Transmission Owners note that the 
Midwest ISO pro forma Generator Interconnection Agreement (GIA) applies 
to all interconnection customers, regardless of size, and as a result 
any reporting requirements adopted in the GIA should apply to 
generators with a capacity of less than 20 MW. California PUC asks that 
the Commission make clear that public utility transmission providers 
are not prohibited from requesting meteorological and operational data 
from small VERs. Environmental Defense Fund states that the Commission 
should host a technical conference to examine issues arising from 
requiring small generators to contribute information to support power 
production forecasting.
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    \218\ E.g., Bonneville Power; Idaho Power.
---------------------------------------------------------------------------

    191. Some commenters address other aspects of the Commission's 
proposal to amend the pro forma LGIA. AWEA questions the Commission's 
preliminary conclusion that the LGIA provides sufficient 
confidentiality protection for sensitive operational and meteorological 
data, stating that vendors providing forecasts to public utility 
transmission providers must not be allowed to use the data they collect 
for developing forecasts for the public utility transmission provider 
for any other purpose without express agreement. MidAmerican asks the 
Commission to clarify that there will not be any additional penalties 
for failure to provide accurate meteorological and operational data, 
other than the contractual remedies for breach already provided for in 
the pro forma LGIA. MidAmerican states that it recognizes that 
meteorological data are not always available if, for example, 
communication from a collecting device is interrupted. RenewElec 
recommends that the Commission set forth a data retention requirement 
in the new pro forma LGIA Article 8.4 that would require public utility 
transmission providers to maintain data collected from interconnection 
customers whose generating facilities are VERs for at least 10 years, 
facilitating follow-up studies to update power production forecasts.
f. Commission Determination
    192. The Commission affirms the Proposed Rule and amends the pro 
forma LGIA to include a new Article 8.4 setting forth the reporting 
requirements adopted in this Final Rule. The Commission directs all 
public utility transmission providers to file a revised pro forma LGIA 
within 12 months of the effective date of this Final Rule reflecting 
the revisions adopted herein. As noted below, public utility 
transmission providers that have already implemented meteorological or 
forced outage reporting requirements may seek to demonstrate, on 
compliance, that these existing business practices and market rules 
adequately satisfy the requirements of this Final Rule.
    193. As set forth in the Proposed Rule, Article 8.4 of the pro 
forma LGIA did not state where the meteorological and forced outage 
data reporting requirements would be specified in an LGIA. The 
Commission agrees with Bonneville Power that it is appropriate to state 
reporting requirements for meteorological and forced outage data in 
Appendix C, Interconnection Details, as this will allow the 
requirements to be changed from time to time. The Commission therefore 
revises proposed Article 8.4 to specify that reporting requirements for 
meteorological and forced outage data would be set forth in Appendix C, 
Interconnection Details, of an LGIA. A transmission provider with an 
executed LGIA that seeks reporting of such data may negotiate revisions 
to Appendix C related to such reporting requirements with the 
interconnection customer. To the extent the parties mutually agree on 
changes to Appendix C, such changes to Appendix C need not be submitted 
to the Commission for review. If the parties are unable to reach 
agreement on proposed modifications to Appendix C, however, these 
parties may invoke their rights, as relevant, to modify the LGIA under 
sections 205 or 206 of the FPA, as appropriate, and pursuant to Article 
30.11 of the LGIA.
    194. The Commission disagrees with commenters suggesting that 
flexibility provided by business practices or market rules makes them a 
superior alternative for implementing the meteorological and forced 
outage reporting requirements adopted in this Final Rule. The 
Commission has sought to address public utility transmission providers' 
need for flexibility by clarifying that reporting requirements are to 
be set forth in Appendix C to the LGIA, while also addressing 
interconnection customers' need for certainty in the obligations placed 
on them. The Commission appreciates that public utility transmission 
providers in some regions, including RTOs and ISOs, have already 
implemented meteorological or forced outage reporting under business 
practices and markets rules. Such public utility transmission providers 
may seek to demonstrate in their compliance filing how continued use of 
these existing business practices and market rules is adequate to 
satisfy the requirements of this Final Rule using the independent 
entity variation standard set forth in Order No. 2003, if relevant, or 
by demonstrating variations from the pro forma OATT are consistent with 
or superior to the requirements of this Final Rule.\219\
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    \219\ Order No. 2003, FERC Stats. & Regs. ] 31,146 at PP 9-10.
---------------------------------------------------------------------------

    195. The Commission declines to modify existing LGIAs already in 
effect to include Article 8.4 of the pro forma LGIA as adopted in this 
Final Rule. The Commission acknowledges that, in some situations, there 
may be a sufficient amount of VERs already interconnected to the public 
utility transmission provider's system to make data from those 
resources useful or even necessary to properly implement power 
production forecasting. However, several considerations lead us to 
decline to modify every LGIA in effect on a generic basis. First the 
Commission believes retroactive changes to every LGIA in effect could 
be administratively burdensome to public utility transmission providers 
and interconnection customers, especially where the public utility 
transmission provider is not engaged in power production forecasting. 
Second, we note that nothing in the pro forma LGIA precludes the 
parties to an LGIA from mutually agreeing to revise the requirements 
set forth in Appendix C to reflect the reporting of meteorological and 
forced outage data. Indeed, we note that Article 9.4 of the pro forma 
LGIA recognizes that Appendix C will be modified to reflect changes to 
the interconnection customer's requirements as they may change from 
time to time. Finally, if the parties are unable to agree to 
modifications of Appendix C, we note that pursuant to Article 30.11 of 
the pro forma LGIA, the transmission provider has the right to make a 
unilateral filing to the Commission proposing to modify an

[[Page 41515]]

existing LGIA under section 205 of the FPA.
    196. For similar reasons, the Commission declines suggestions to 
implement data reporting requirements through the pro forma OATT 
instead of the pro forma LGIA or to include the requirements in the pro 
forma SGIA. The effect of relying on the pro forma OATT would be to 
impose the data reporting requirements adopted in this Final Rule on 
existing interconnection customers retroactively, including those with 
resources under 20 MW that are subject to the pro forma SGIA. Like data 
from existing resources, data from small resources may be useful or 
necessary for power production forecasting, yet the record in this 
proceeding does not demonstrate that the need for data from small 
resources is so great as to outweigh the potential burden that 
reporting requirements could impose on smaller resources. Just as the 
pro forma LGIA provides an opportunity for public utility transmission 
providers to mutually agree with interconnection customers regarding 
reporting requirements, nothing in the pro forma SGIA precludes the 
transmission provider from negotiating with the owners and operators of 
small VERs to update their SGIAs to provide for the reporting of 
meteorological and forced outage data that are necessary for public 
utility transmission providers to employ power production forecasting. 
As with the pro forma LGIA, section 12.12 of the pro forma SGIA 
provides an opportunity for parties to an SGIA to bring any 
disagreement to the Commission for resolution.
    197. In response to Midwest ISO Transmission Owners, the Commission 
notes that the extent to which a new LGIA is necessitated by a new 
Interconnection Request or Material Modification is governed by the pro 
forma LGIA and Commission precedent. To the extent a new LGIA is 
warranted, the VER interconnection customer would be subject to the 
relevant requirements of this Final Rule in effect at the time. Public 
utility transmission providers may seek to demonstrate in their 
compliance filings how continued use of existing tariffs, business 
practices and/or market rules is adequate to satisfy the requirements 
of this Final Rule using the independent entity variation standard set 
forth in Order No. 2003, if relevant, or by demonstrating variations 
from the pro forma OATT are consistent with or superior to the 
requirements of this Final Rule.\220\
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    \220\ See Id. P 910.
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    198. With regard to AWEA's concern regarding the confidentiality of 
data, the Commission agrees that meteorological and forced outage data 
can be commercially sensitive, but concludes that the Article 22 of the 
pro forma LGIA provides adequate safeguards for reported data.\221\ Any 
vendor providing forecasts to a public utility transmission provider 
would be an agent of the public utility transmission provider subject 
to the confidentiality obligations of the pro forma LGIA. With regard 
to MidAmerican's concern regarding penalties for failure to provide 
accurate meteorological and forced outage data, the Commission notes 
that the extent to which penalties beyond those set forth in the pro 
forma LGIA might be appropriate for failing to satisfy data reporting 
requirements will necessarily depend on the facts and circumstances 
surrounding each instance of failed reporting. The Commission 
appreciates that unforeseen circumstances may impair an interconnection 
customer's ability to report data and that the impact of failed 
reporting may in many instances be de minimus. However, it would not be 
appropriate for the Commission to conclude generically that in no 
circumstance would additional penalties beyond those remedies set forth 
in the pro forma LGIA be appropriate for failure to comply with the 
data reporting requirements of an executed LGIA.
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    \221\ Article 22 of the pro forma LGIA defines Confidential 
Information to include, among other things, all information relating 
to a Party's technology, research and development, business affairs, 
and pricing. Each party to an LGIA must hold in confidence and may 
not disclose to any person Confidential Information during the term 
of an LGIA and for a period of three years after the expiration or 
termination of an LGIA.
---------------------------------------------------------------------------

    199. Finally, the Commission declines to impose special retention 
requirements for reported meteorological and forced outage data as 
requested by RenewElec. The time period over which a public utility 
transmission provider would need to retain meteorological or forced 
outage data will be a function of the type of power production 
forecasting being employed by the public utility transmission provider.
2. Definition of VER
a. Commission Proposal
    200. In the Proposed Rule, the Commission sought to modify the pro 
forma LGIA to include a new definition for Variable Energy Resource in 
Article 1. The proposed definition identified a Variable Energy 
Resource as a device for the production of electricity that is 
characterized by an energy source that: (1) Is renewable; (2) cannot be 
stored by the facility owner or operator; and (3) has variability that 
is beyond the control of the facility owner or operator.\222\ The 
Commission stated that it believed the proposed definition was 
consistent with NERC's characterization of variable generation.\223\
---------------------------------------------------------------------------

    \222\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 64.
    \223\ Id. (citing NERC, Accommodating High Levels of Variable 
Generation 13-14 (2009), available at https://www.nerc.com/files/IVGTF_Report_041609.pdf).
---------------------------------------------------------------------------

b. Comments
    201. EEI supports the Commission's proposed definition without 
modification. California ISO supports the definition's focus on source 
of energy, but suggests that the phrase ``by an energy source that'' be 
replaced with ``by a fuel source that.'' California ISO states that 
this change would make clear that the three conditions that follow 
pertain to the fuel source and not the nature of the facility itself.
    202. Other commenters disagree with the focus on the source of 
energy, arguing that a VER should be defined by reference to its 
operating characteristics, including the ability to control 
output.\224\ BrightSource states that this would allow for comparison 
between facilities with different fuel sources on standard operational 
and reliability time-frames and also avoid confusion about types of 
plants that combine renewable and conventional fuel sources, such as 
solar-gas hybrids. Joined by SEIA, BrightSource argues that a plant 
able to maintain a high level of operational control comes close to 
fulfilling the operational characteristics of a non-VER generation and 
should be treated as such for purposes of the Proposed Rule's 
requirements. NextEra agrees, stating that some resources can control 
the variability of their facility by adjusting output through 
feathering blades, self-curtailment, or similar measures. SEIA suggests 
that the Commission consider alternative criteria that could provide a 
distinction between VERs with a high level of control and VERs without 
such controls, such as if actual production can remain within some 
statistical measure of forecast accuracy during its operating hours. 
MidAmerican similarly requests that the Commission adopt a definition 
based on physical electrical generation output characteristics rather 
than input attributes such as fuel type, suggesting that whether energy 
sources qualify as ``renewable'' varies among states that have 
developed their own renewable resource regulations.
---------------------------------------------------------------------------

    \224\ E.g., AWEA; BrightSource; NaturEner; NextEra; RenewElec; 
SEIA.

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[[Page 41516]]

    203. Several of these commenters question the applicability of the 
proposed definition to resources that use energy storage to control 
output. NaturEner provides a hypothetical example of a plant coupled 
with storage and asks that the Commission provide clarification 
regarding the impact of such pairing on capacity reserve obligations. 
BrightSource asks the Commission to modify the definition to address 
how much storage results in a plant not being considered a VER for 
purposes of the Proposed Rule and any future rules. AWEA and NextEra 
request clarification that the proposed definition would not prevent 
VERs from electing to maintain VER status even if they use energy 
storage, other firming technologies, or otherwise have the ability to 
adjust output. RenewElec and SEIA argue that, regardless of the 
Commission's determination on the storage issue for VERs, such 
resources should not be exempt from reporting meteorological data to 
their public utility transmission provider. BrightSource and SEIA state 
that the applicability of the proposed definition is sufficiently 
important that the Commission should consider a technical conference on 
the issue.
    204. Some commenters focus on the applicability of the proposed 
definition to particular types of resources, such as tidal, run-of-
river hydro, conduit hydro, co-generation, or biomass.\225\ Snohomish 
County PUD argues that, although such facilities would appear to 
satisfy the proposed definition, they should not be required to report 
the proposed data to public utility transmission providers because the 
data reporting would provide minimal benefit to grid operators while 
imposing a significant burden on these resources. Focusing on run-of-
river hydro, Snohomish County PUD contends that whether such a facility 
is available at any given moment has no impact on the extent to which a 
sudden wind ramp might change production on the grid. NorthWestern and 
Pacific Gas & Electric agree, arguing that run-of-river hydro is much 
more predictable than wind or solar generation on a short-term basis 
and, as a result, there would be little benefit to collecting the 
meteorological data from such resources. In contrast, Entergy argues 
that the proposed definition and associated reporting requirements 
should be imposed on Qualifying Facilities to avoid gaps in forecasting 
and to allow public utility transmission providers to accommodate the 
variability that exists with both Qualifying Facilities and VERs.
---------------------------------------------------------------------------

    \225\ E.g., Grays Harbor PUD; NorthWestern; Pacific Gas & 
Electric; Snohomish County PUD.
---------------------------------------------------------------------------

    205. Other commenters question the application of the proposed 
definition to solar resources.\226\ California ISO explains that while 
solar thermal resources store solar thermal heat, they do not store 
solar irradiance itself, which is the energy source for the solar 
thermal facility. California ISO asks the Commission to clarify that a 
solar thermal facility would fall under the proposed definition. 
BrightSource contends that the storage and variability elements of the 
proposed definition appear to overlap functionally for a solar thermal 
plant, given that variability during the operating day could be 
controlled in many ways by the facility. BrightSource requests 
clarification regarding whether a VER would have to meet both or just 
one of these elements to fall within the definition.
---------------------------------------------------------------------------

    \226\ E.g., BrightSource; California ISO.
---------------------------------------------------------------------------

    206. ISO New England and NorthWestern offer opposing views on 
application of the proposed definition and associated reporting 
requirements on behind-the-meter generation. ISO New England recommends 
that all distributed or behind-the-meter generation should be required 
to provide to the balancing and transmission entities in its area, at a 
minimum, specification of the technology and precise location of the 
installed resource so that a forecast of output can be developed on an 
aggregate scale to include in the balancing area forecast.
    207. California State Water Project argues that its wholesale 
participating load resource also meets the definition of a VER. 
California State Water Project explains that participating load's 
primary purpose is not the provision of services to the grid, but 
rather water management, and that the load is subject to variability 
for reasons beyond California State Water Projects' control, such as 
competing environmental and water management requirements. Accordingly, 
California State Water Project requests that consideration be given to 
expanding the VERs definition to include large wholesale demand 
response resources that bid into markets not through a baseline 
mechanism, but rather on a basis comparable to generation.
    208. ISO New England requests that the Commission afford 
flexibility for entities to use existing, superior definitions of VERs. 
The ISO New England Tariff already uses the term ``Intermittent Power 
Resources'' for wind, solar, run-of-river hydro and other renewable 
resources that do not have control over their net power output. As 
such, ISO New England requests that the Commission allow entities to 
use existing, superior approaches to the extent these are consistent 
with the objectives of the proposed reforms. ISO New England states 
that adding another term to its tariff could potentially lead to 
confusion, and therefore, argues that the region should be afforded the 
opportunity to consider the existing terminology in the ISO New England 
Tariff, and determine whether any changes are warranted.
    209. Bonneville Power states that, in light of its position that 
the pro forma LGIA provides transmission providers with the authority 
to update operational requirements for VERs, the Commission's proposed 
definition is unnecessary. However, Bonneville Power nonetheless states 
that it supports the inclusion of the proposed definition in all new 
VER interconnection agreements.
c. Commission Determination
    210. The Commission adopts the Proposed Rule's definition of VER 
and, accordingly, amends Article 1 of the pro forma LGIA to include the 
following definition:

    Variable Energy Resource shall mean a device for the production 
of electricity that is characterized by an energy source that: (1) 
is renewable; (2) cannot be stored by the facility owner or 
operator; and (3) has variability that is beyond the control of the 
facility owner or operator.

The Commission finds it necessary to define VERs in the pro forma LGIA 
in order to identify those resources that are required to provide to 
their public utility transmission provider meteorological and forced 
outage data necessary to enable the public utility transmission 
provider to develop and deploy power production forecasting. The 
Commission therefore declines to define VERs by their operating 
characteristics as suggested by BrightSource and MidAmerican or by 
reference to their lack of ability to store output, self-curtail 
production, or otherwise firm deliveries as suggested by BrightSource, 
NextEra and others. The Commission also declines to define VERs by 
their fuel type as suggested by California ISO, because fuel type is an 
unduly restrictive subset of energy type.\227\
---------------------------------------------------------------------------

    \227\ ``Fuel'' is defined as a material used to produce heat or 
power by burning. See Merriam Webster, https://www.Merriam-Webster.com, 2011. (November 4, 2011).
---------------------------------------------------------------------------

    211. As noted elsewhere in this Final Rule, power production 
forecasting

[[Page 41517]]

allows the public utility transmission provider to understand the 
characteristics of the input energy source for particular resources, to 
use those characteristics to predict how the resources will operate, 
and in turn to determine whether and to what degree the public utility 
transmission provider will need to reserve capacity to manage 
variability in generation output. Therefore, it is the variability of 
the energy source, not the operating characteristics of the plant or 
nature of output, that are critical to identifying the set of resources 
that must be subject to the meteorological and forced outage data 
requirements adopted above. Defining VERs by reference to operating 
characteristics or level of storage could limit the reporting of data 
in ways that undermines that ability of public utility transmission 
providers to engage in power production forecasting.
    212. The Commission declines to establish an exemption to the data 
reporting requirements in this Final Rule for VERs utilizing energy 
storage or other firming technologies. Not only would this exemption 
inhibit the public utility transmission provider's capacity to predict 
how the VER resources will operate, but there is also insufficient 
evidence in this record to identify an objective threshold for 
exemption. The Commission clarifies that the purpose of this definition 
is to identify the resources that are required by this Final Rule to 
provide to their public utility transmission provider meteorological 
and forced outage data; the purpose is not, as suggested by NaturEner, 
to assign capacity reserve obligations or other charges. Nor does this 
definition supersede those created by other entities for purposes 
outside this rule, such as tax benefit purposes or renewable energy 
credits.
    213. For similar reasons, the Commission declines to limit the VER 
definition in the pro forma LGIA to solar and wind resources so as to 
exclude run-of-river hydro, tidal, or other new and emerging VER 
technologies. Although the Commission anticipates that public utility 
transmission providers initially will engage in power production 
forecasting predominantly for wind and solar VERs, we leave to the 
public utility transmission providers to determine whether their 
individual systems necessitate power production forecasting for other 
types of VERs. Categorically excluding other types of resources would 
undermine the flexibility being provided in this Final Rule. At the 
same time, we decline to establish minimum reporting requirements for 
non-wind and non-solar VERs and leave to the public utility 
transmission providers and VERs to negotiate what data are necessary 
for developing and deploying power production forecasting for these 
resources, taking into account the size and configuration of the VER, 
its characteristics, location, and its importance in maintaining 
generation resource adequacy and transmission system reliability in its 
area.\228\ Because such requirements will vary system by system, it is 
not necessary to hold a technical conference to explore generic 
application of the VER definition as suggested by BrightSource and 
SEIA.
---------------------------------------------------------------------------

    \228\ If parties are unable to reach an agreement the public 
utility transmission provider may submit a filing requesting the 
data and demonstrating how it will be used for power production 
forecasting pursuant to section 205 of the FPA.
---------------------------------------------------------------------------

    214. In response to California State Water Project, the Commission 
clarifies that VERs are not defined herein to include demand response 
resources. A demand response resource is not a device for the 
production of electricity and, therefore, would not fall within the VER 
definition adopted in the pro forma LGIA.\229\ In response to ISO New 
England and NorthWestern, the definition potentially could apply to 
behind-the-meter generation, although such resources would only be 
subject to data reporting requirements adopted in this Final Rule to 
the extent they enter into a new LGIA or materially modify an existing 
LGIA after the effective date of this Final Rule.
---------------------------------------------------------------------------

    \229\ A demand response resource may use behind-the-meter 
generation, potentially including VERs, to facilitate the provision 
of demand response. Such use, however, does not mean that such 
behind-the-meter generation is itself a demand response resource.
---------------------------------------------------------------------------

    215. ISO New England inquires as to the impact of the VER 
definition on other definitions in a public utility transmission 
provider's existing tariff. As noted above, public utility transmission 
providers that are RTOs or ISOs may seek to demonstrate in their 
compliance filing how existing tariffs, business practices or market 
rules are adequate to satisfy the requirements of this Final Rule using 
the independent entity variation standard set forth in Order No. 2003, 
if relevant, or by demonstrating variations from the pro forma OATT are 
consistent with or superior to the requirements of this Final Rule.
    216. With regard to Entergy's request that the Commission apply the 
proposed outage reporting requirement to Qualifying Facilities, we 
clarify that the data-reporting requirements under this rule apply to 
interconnection customers whose generating facilities are VERs as 
defined herein. Specifically, when an electric utility purchases an 
interconnected Qualifying Facility's total output, the relevant state 
authority exercises authority over the interconnection and the 
allocation of interconnection costs. But when an electric utility 
interconnecting with a Qualifying Facility does not purchase all of the 
Qualifying Facility's output and instead transmits the Qualifying 
Facility power in interstate commerce to another purchaser, the 
Commission exercises jurisdiction over the rates, terms, and conditions 
affecting or related to such service, such as interconnections.\230\ 
Thus, for a Qualifying Facility that is a VER, when the interconnected 
Qualifying Facility is selling its total output to an electric utility, 
the meteorological and forced outage reporting requirements of this 
Final Rule do not apply. However, when an electric utility 
interconnecting with a Qualifying Facility does not purchase all of the 
Qualifying Facility's output and instead transmits the Qualifying 
Facility power in interstate commerce to another purchaser, the 
meteorological and forced outage reporting requirements of this Final 
Rule are applicable.
---------------------------------------------------------------------------

    \230\ Order No. 2003, FERC Stats. & Regs. ] 61,103 at P 813. The 
Commission regulations governing the exemptions enjoyed by 
Qualifying Facilities are codified at 18 CFR Part 292, Subpart F (18 
CFR 292.601-292.602 (2011)). Limited exemptions from sections 205 
and 206 of the FPA apply to certain sales of energy and capacity 
made by Qualifying Facilities. See also Terra-Gen Dixie Valley, LLC, 
132 FERC ] 61,215, at PP 45-46 (2010).
---------------------------------------------------------------------------

3. Data Sharing
a. Commission Proposal
    217. In the Proposed Rule, the Commission sought comment on whether 
public utility transmission providers should be allowed or required to 
share VER-related data received from interconnection customers with 
other entities, like the source or sink balancing authority area for a 
transaction, or a government agency, such as NOAA, assuming 
confidentiality is protected.\231\
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    \231\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 63.
---------------------------------------------------------------------------

b. Comments
    218. Clean Line and RenewElec state that operational and 
meteorological data should be made public to the maximum extent 
possible. RenewElec argues that there is a significant lack of 
operational data available to researchers in the area of VERs 
integration, and asks that the Commission require that: (1) VER data be 
made public within six months of the date on which such data is 
submitted by the interconnection customer, and (2)

[[Page 41518]]

operational data, including VER data, used by transmission providers to 
develop VER power production forecasting be made available to 
interested parties.
    219. While generally stating support for the sharing of data, some 
commenters raise confidentiality concerns and point out the 
commercially-sensitive nature of data subject to the reporting 
requirements contemplated in the Proposed Rule.\232\ For example, 
Southern California Edison supports sharing VER-related data for the 
purposes of increasing forecasting accuracy, as long as the data are 
not proprietary data that the public utility transmission provider is 
prohibited from disclosing to other parties. Bonneville Power and a few 
others contend that while sharing data from individual VERs poses 
confidentially issues, sharing aggregate VER data does not pose the 
same problems.\233\ Sunflower and Mid-Kansas state that, within RTOs, 
the stakeholders should decide which entities should be provided VER 
data. Western Farmers request that the Commission confirm that, where 
the transmission provider is not the balancing authority, the data 
should also be provided to the relevant balancing authority. NextEra 
and AWEA only support sharing data with other balancing authorities 
when the resource is being dynamically scheduled or dispatched into 
that balancing authority. Bonneville Power suggests that, at a minimum, 
the Commission should allow public utility transmission providers and 
balancing authorities to share aggregate forecasts for VER output with 
all parties to an e-tag.
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    \232\ E.g., CGC; California PUC; EEI; NextEra; PJM; SMUD; ISO 
New England.
    \233\ E.g., Bonneville Power; California ISO; Exelon; SEIA.
---------------------------------------------------------------------------

    220. Several commenters support sharing VER-related meteorological 
data with NOAA, including having the data incorporated into 
foundational models run by NOAA.\234\ Commenters, including NOAA, 
request that the Commission require VERs to submit meteorological data 
to NOAA for the purpose of improving atmospheric characterization and 
forecast accuracy.\235\ In response to confidentiality concerns, NOAA 
states that private sector proprietary data can be protected from 
distribution and anonymized in the analysis and generation of 
forecasts, which would then allow improved predictions to be available 
for the private sector to incorporate into power production forecasts.
---------------------------------------------------------------------------

    \234\ E.g., AWEA; Bonneville Power; CGC; Iberdrola; ISO New 
England; MidAmerican; NaturEner; NOAA.
    \235\ E.g., Bonneville Power; Iberdrola; NOAA.
---------------------------------------------------------------------------

c. Commission Determination
    221. The Commission declines to expand the Proposed Rule to require 
public utility transmission providers to share VER related data with 
other entities such as a balancing authority area or NOAA. However, the 
Commission strongly encourages the voluntary sharing of data where 
appropriate. Many commenters assert that significant benefits might 
flow from VERs sharing data with entities such as a balancing authority 
area or NOAA. The Commission finds that VERs are in the best position 
to negotiate what data are needed and to weigh the benefits that may be 
expected as a result of providing such data. In addition, negotiating 
directly with other entities will allow VERs to ensure that adequate 
confidentiality protections are in place for information that they may 
consider to be commercially sensitive or otherwise confidential. If 
helpful to industry participants, the Commission will consider making 
staff available to work through issues and, if appropriate, take 
additional steps to facilitate the voluntary sharing of information.
4. Cost Recovery
a. Commission Proposal
    222. In the Proposed Rule, the Commission refrained from proposing 
a single method of cost recovery for the development and implementation 
of power production forecasts. Instead, the Commission sought comments 
on how public utility transmission providers may recover costs incurred 
to develop and deploy power production forecasting tools.\236\
---------------------------------------------------------------------------

    \236\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 57.
---------------------------------------------------------------------------

b. Comments
    223. Among those seeking flexibility, AWEA states that the 
Commission is correct to not propose a single uniform method for 
allocating these costs, and instead should defer to public utility 
transmission providers and others to determine how these costs should 
be allocated. Several commenters request that the Final Rule provide 
flexibility to public utility transmission providers and/or regions to 
propose cost recovery approaches.\237\ For example, EEI contends that 
generally no interconnected resource should be exempt from the 
responsibility for costs that it causes to be incurred, but asks that 
the Commission not mandate how costs should be allocated at this time, 
allowing regions to develop appropriate cost-recovery solutions.
---------------------------------------------------------------------------

    \237\ E.g., AWEA; California PUC; Duke; ISO New England; 
MidAmerican; Pacific Gas & Electric.
---------------------------------------------------------------------------

    224. Some commenters recommend that the cost of forecasting be 
spread among all transmission customers.\238\ Independent Power 
Producers Coalition-West argues that forecasting tools will ultimately 
reduce costs to utilities and generators, and will ultimately be a 
small cost of doing business in a world where forecasting can and 
should be a constant element of the power scheduling process. Public 
Interest Organizations state that the costs of centralized forecasting 
infrastructure should be spread across all those who benefit from the 
improved accuracy and decreased costs, provided those costs are 
demonstrated to be just and reasonable. Joined by NextEra, Public 
Interest Organizations argue that the broad benefits of forecasting 
justify the sharing of related costs across the transmission system(s) 
that benefit.
---------------------------------------------------------------------------

    \238\ E.g., Iberdrola; Independent Power Producers Coalition-
West; NextEra; Public Interest Organizations; Exelon.
---------------------------------------------------------------------------

    225. Iberdrola contends that there is no difference in the costs 
incurred to develop and deploy power production forecasting tools and 
the costs of developing and implementing other market design features. 
Iberdrola states that these types of costs typically are not directly 
assigned to one set of market participants, but are spread to all users 
of the transmission system because they benefit all users of the 
system. Iberdrola states that the costs incurred to develop and deploy 
power production forecasting tools should similarly be spread to all 
system users.
    226. Exelon recommends recovering the cost of forecasting within 
administrative charges, the approach taken by PJM and ERCOT. Exelon 
provides an example of ERCOT's handling of the costs: the cost of 
developing the ramp probability tool was a one-time investment that was 
recovered by the transmission provider in uplift to the market. The 
ongoing cost of using the tool is also spread across the market. Exelon 
states that this approach avoids the problem of free-ridership by 
future market participants that would occur if these costs were 
recovered solely from existing market participants.
    227. Other commenters argue either that the VERs, or the 
beneficiaries of VERs, should be financially responsible for the costs 
of forecasting.\239\ These

[[Page 41519]]

commenters generally contend that public utility transmission providers 
should be able to recover the costs incurred to develop and deploy 
power production forecasting by imposing a fee or rate upon the VERs 
causing the costs to be incurred. For example, NRECA argues that non-
VER transmission customers are neither causing nor benefiting from the 
enhancements to power production forecasting and, therefore, should not 
be forced to subsidize its costs, citing Northern States Power 
Company.\240\ Montana PSC suggests that all VERs of 1 MW or greater 
should be responsible for power production forecasting costs. Pacific 
Gas & Electric notes the approach taken in the California ISO's 
Participating Intermittent Resources Program, in which the California 
ISO charges a fee to VERs to recover costs to develop and deploy power 
production forecasts.
---------------------------------------------------------------------------

    \239\ E.g., Bonneville Power; ELCON; Large Public Power Counci; 
MidAmerican; Midwest ISO Transmission Owners; Montana PSC; 
NorthWestern; NRECA; Oregon & New Mexico PUC; PNW Parties; SMUD; 
Southern California Edison; Tacoma Power.
    \240\ NRECA (citing N. States Power Co., 64 FERC ] 61,324, at P 
63,379 (1993)).
---------------------------------------------------------------------------

    228. ELCON and Tacoma Power argue that any resource, whether or not 
it is a VER, should be held fully accountable for the costs it causes 
the transmission provider to incur on its behalf. ELCON argues that 
meteorological forecasting is simply a cost of doing business for wind 
energy, just as a nuclear power plant must pay for storage of spent 
fuel. ELCON argues that these costs should not be recovered in uplift 
charges in regions served by ISOs or RTOs, or allocated to non-
customers of VER transactions.
    229. SEIA recommends that the Commission examine whether there may 
be market entities that would consider contributing to the costs of the 
forecast service providers in the non-organized market regions, e.g., 
power traders may be willing to pay for the aggregate day-ahead and 
hour-ahead forecasts across such regions. SEIA states that these 
revenues could be used to develop aggregated forecasts for more 
geographical areas within a region that could further reduce 
integration costs.
    230. Duke argues that the Commission should allow public utility 
transmission providers to update any costs associated with the Proposed 
Rule's reporting and power production forecasting requirements without 
triggering a general rate case. Duke suggests that one possible option 
would be through a formula rate that is updated periodically for 
changes in costs related to forecasting and data reporting.
    231. Finally, some commenters request that the Commission recognize 
that the costs of centralized forecasting go beyond the expense of 
forecasting tools.\241\ These additional costs include gathering data, 
installing and operating onsite telemetry, equipment to record 
meteorological data, and data management. Southern California Edison 
points out that data and telemetry are only as good as the personnel 
assessing the information.
---------------------------------------------------------------------------

    \241\ E.g., Pacific Gas & Electric; Southern California Edison; 
NorthWestern.
---------------------------------------------------------------------------

c. Commission Determination
    232. The Commission finds that it is not necessary to prescribe a 
single method of cost recovery for developing and implementing power 
production forecasting, as it is likely that not all public utility 
transmission providers will develop power production forecasting, given 
regional differences in the types and penetration of VERs. Moreover, 
the record in this proceeding demonstrates that the circumstances under 
which a public utility transmission provider may decide to develop and 
deploy power production forecasting may vary by system. In some 
instances, public utility transmission providers might develop and 
employ power production forecasting in order to manage more effectively 
the commitment of reserves associated with the provision of generator 
regulation service, as discussed in other sections of this Final Rule. 
In other circumstances, public utility transmission providers might 
develop and employ power production forecasting to manage reserve costs 
recovered under other ancillary services. In addition, public utility 
transmission providers may seek to recover costs associated with power 
production forecasting in different ways, as cost recovery may be 
sought via a general rate case, formula rate, or other mechanism. Given 
the myriad of factors that may be relevant to the allocation and 
recovery of such costs, the Commission finds it appropriate to evaluate 
requests for the recovery of costs incurred to develop and deploy power 
production forecasts on a case-by-case basis consistent with FPA 
section 205 and Commission precedent.

C. Generator Regulation Service-Capacity

    233. In the Proposed Rule, the Commission preliminarily found that 
clarifying the manner by which public utility transmission providers 
may recover the costs associated with fulfilling their obligation to 
offer generator regulation service would remove barriers to the 
integration of VERs by eliminating public utility transmission 
providers' uncertainty regarding cost recovery.\242\ As discussed 
below, the Commission concludes that adoption of this reform could 
inhibit the flexibility to design capacity services that align with the 
operational practices or needs of a particular public utility 
transmission provider. The Commission therefore declines to adopt a 
generic Schedule 10 for generation regulation service this reform and 
instead provides guidance to assist public utility transmission 
providers and their customers in the development and evaluation of 
proposals related to recovering the costs of regulation reserves 
associated with VER integration.
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    \242\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 87.
---------------------------------------------------------------------------

1. Schedule 10--Generator Regulation and Frequency Response Service
    234. In the Proposed Rule, the Commission proposed incorporating 
into the pro forma OATT a new ancillary service schedule for Generator 
Regulation and Frequency Response Service. The Commission introduced 
this proposal with a review of the adoption in Order Nos. 888 \243\ and 
890 \244\ of ancillary services schedules for Regulation and Frequency 
Response Service (regulation service), energy imbalance service, and 
generator imbalance service.\245\ The Commission repeats that 
introduction here for background.
---------------------------------------------------------------------------

    \243\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,703-04.
    \244\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 627.
    \245\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at PP 66-71.
---------------------------------------------------------------------------

    235. Regulation service, offered under Schedule 3 of the pro forma 
OATT, provides the capacity reserve necessary for the continuous 
balancing of resources (generation and interchange) with load to 
maintain a scheduled interconnection frequency of 60 cycles per second 
(60 Hz).\246\ In Order No. 888, the Commission required public utility 
transmission providers to offer regulation service for transmission 
service within or into the public utility transmission provider's 
balancing authority area to serve load in that area.\247\ However, the 
Commission did not require public utility transmission providers to 
offer regulation service for transmission service out of or through the 
public utility transmission provider's balancing authority area to

[[Page 41520]]

serve load in another balancing authority area.\248\
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    \246\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,707-08.
    \247\ Id. at 31,717.
    \248\ Id.
---------------------------------------------------------------------------

    236. Energy imbalance service, offered under Schedule 4 of the pro 
forma OATT, accounts for hourly energy deviations between a 
transmission customer's scheduled delivery of energy and the actual 
energy used to serve load.\249\ In Order No. 888, the Commission 
required public utility transmission providers to offer energy 
imbalance service for transmission service within and into the public 
utility transmission provider's balancing authority area to serve load 
in that area.\250\ Like regulation service, the Commission did not 
require public utility transmission providers to offer energy imbalance 
service for transmission service being used to serve load in another 
balancing authority area.
---------------------------------------------------------------------------

    \249\ Id. at 31,708.
    \250\ Id. at 31,717.
---------------------------------------------------------------------------

    237. Regulation service and energy imbalance service, while 
different in function, are complementary services through which public 
utility transmission providers maintain their systems' balance and 
recover both the capacity (regulation service) and energy (energy 
imbalance service) costs of doing so from transmission customers 
serving load on their systems. At the time of Order No. 888, the 
Commission believed that it was reasonable to provide only standardized 
ancillary service schedules for transmission used to service load 
because load (rather than generation) exhibited the greatest amount of 
variability.\251\ The Commission noted that generators should be able 
to deliver scheduled hourly energy with precision and that the 
requirements for generators to meet their schedules should be contained 
in interconnection agreements.
---------------------------------------------------------------------------

    \251\ In 1996, when Order No. 888 was developed and issued, wind 
generation was not a significant energy source, with a total 
capacity of approximately 1,698 MW. See Imbalance Provisions for 
Intermittent Resources; Assessing the State of Wind Energy in 
Wholesale Electricity Markets, Notice of Proposed Rulemaking, FERC 
Stats. & Regs. ] 32,581, at P 7 (2005).
---------------------------------------------------------------------------

    238. In Order No. 890, the Commission noted that the existing 
energy imbalance charges were the subject of significant concern and 
confusion in the industry.\252\ The Commission expressed concern about 
the variety of different methodologies used for determining imbalance 
charges and whether the level of the charges provided the proper 
incentive to keep schedules accurate without being excessive.\253\ Such 
concerns led the Commission to revise existing pro forma energy 
imbalance service provisions and require public utility transmission 
providers to offer a new service, generator imbalance service, to 
account for hourly energy deviations between a transmission customer's 
scheduled delivery of energy from a generator and the amount of energy 
actually generated.\254\ The Commission found that formalizing 
generator imbalance provisions in the pro forma OATT would standardize 
future treatment of such imbalances, thereby lessening the potential 
for undue discrimination, increasing transparency, and reducing 
confusion in the industry that resulted from the then current plethora 
of different approaches.
---------------------------------------------------------------------------

    \252\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 634.
    \253\ Id.
    \254\ Id. P 663.
---------------------------------------------------------------------------

    239. While the pro forma generator imbalance service provides a 
mechanism for public utility transmission providers to recover the cost 
of providing the energy needed to manage hourly generator imbalances, 
it does not provide a mechanism for public utility transmission 
providers to recover the costs of holding reserve capacity associated 
with providing generator imbalance energy.\255\ Although the Commission 
in Order No. 890 did not create a new rate schedule to expressly 
account for these capacity costs, it acknowledged the likelihood that 
such costs would be incurred in connection with the provision of 
generator imbalance service.\256\ Accordingly, the Commission provided 
a mechanism by which public utility transmission providers could 
recover these costs, explaining that ``[t]o the extent a [public 
utility] transmission provider wishes to recover costs of additional 
regulation reserves associated with providing imbalance service, it 
must do so via a separate FPA section 205 filing demonstrating that 
these costs were incurred correcting or accommodating a particular 
entity's imbalances.'' \257\ In Order No. 890-A, the Commission 
clarified that public utility transmission providers may propose to 
assess regulation charges to generators selling in the balancing 
authority area, as well as generators selling outside the balancing 
authority area, and that the Commission will consider such proposals on 
a case-by-case basis.\258\
---------------------------------------------------------------------------

    \255\ Id. P 689 (``The Commission concludes that excluding 
additional regulation costs as a general matter is appropriate 
because much of those costs would be demand costs.'').
    \256\ Id. P 690.
    \257\ Id. at P 689 & n.401 (referring to costs associated with 
capacity used to provide generator imbalance service that otherwise 
are not recovered through Schedule 3).
    \258\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 313.
---------------------------------------------------------------------------

a. Commission Proposal
    240. In the Proposed Rule, the Commission sought to add a new rate 
schedule to the pro forma OATT that complements the generator imbalance 
service provided under Schedule 9 of the pro forma OATT. The Commission 
noted that, in order to meet their obligations to offer generator 
imbalance service under Schedule 9, public utility transmission 
providers must hold unloaded resources in reserve to respond to moment-
to-moment variations attributable to generation. The Proposed Rule 
recognized this de facto obligation and proposed to establish a generic 
rate schedule (Schedule 10--Generator Regulation and Frequency Response 
Service) through which public utility transmission providers may 
recover the costs of providing this service. The Commission 
preliminarily found that clarifying the manner by which public utility 
transmission providers may recover the costs associated with fulfilling 
their obligation to offer this service will remove barriers to the 
integration of VERs by eliminating public utility transmission 
providers' uncertainty regarding cost recovery.\259\
---------------------------------------------------------------------------

    \259\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 87.
---------------------------------------------------------------------------

    241. In the Proposed Rule, the Commission stated that Schedule 10 
is modeled on Schedule 3--Regulation and Frequency Response Service of 
the pro forma OATT. Where Schedule 3 allows public utility transmission 
providers to recover the costs of regulation reserves associated with 
variability of load within its balancing authority area, proposed 
Schedule 10 would provide a mechanism through which public utility 
transmission providers can recover the costs of providing regulation 
reserves associated with the variability of generation resources both 
when they are serving load within the public utility transmission 
provider's balancing authority area and when they are exporting to load 
in other balancing authority areas.\260\
---------------------------------------------------------------------------

    \260\ Id. P 88.
---------------------------------------------------------------------------

    242. The Commission proposed that, consistent with Order No. 890, 
public utility transmission providers would not be permitted to charge 
transmission customers for regulation reserves under both Schedule 3 
and Schedule 10 for the same transaction.\261\ The Commission

[[Page 41521]]

emphasized that in establishing Schedule 10, it was not changing the 
nature of the services that a public utility transmission provider must 
offer its transmission customers. The Commission stated that nothing in 
the Proposed Rule would affect the manner in which balancing 
authorities are required to maintain balanced systems that are operated 
in a safe and reliable fashion, consistent with NERC Reliability 
Standards. The Commission explained that it simply proposed to 
establish a generic cost recovery mechanism for a service that public 
utility transmission providers already are obligated to offer customers 
taking transmission service within their balancing authority area.\262\
---------------------------------------------------------------------------

    \261\ Id. P 89 (citing Order No. 890, FERC Stats. & Regs. ] 
31,241 at P 690 (requiring transmission providers to demonstrate 
that any proposals to recover capacity costs associated with 
Generator Imbalance Service do not lead to double recovery); Entergy 
Serv., Inc., 120 FERC ] 61,042, at PP 62-66 (2007); Sierra Pac. Res. 
Operating Cos., 125 FERC ] 61,026 (2008); Westar Energy Inc., 130 
FERC ] 61,215, at P 4 (2010)).
    \262\ Id. P 91.
---------------------------------------------------------------------------

    243. In the Proposed Rule, the Commission explained that public 
utility transmission providers are not permitted to disclaim the 
obligation to offer to provide transmission customers with the capacity 
reserves associated with the provision of generator imbalance 
service.\263\ Therefore, the Commission proposed that, under Schedule 
10, a public utility transmission provider must offer generator 
regulation service to the extent it is physically feasible to do so 
from its resources or from resources available to it, to transmission 
customers using transmission service to deliver energy from a generator 
located within the public utility transmission provider's balancing 
authority area.\264\
---------------------------------------------------------------------------

    \263\ Id. P 84 (citing NorthWestern, Corp., 129 FERC ] 61,116, 
at P 27 (2009)).
    \264\ Id. P 89.
---------------------------------------------------------------------------

b. Comments
i. Proposed Schedule 10
    244. Although several commenters support the Commission's proposal 
to establish a schedule for the recovery of capacity costs for 
regulation reserves, much of that support is tempered by concern about 
the scope and design of proposed Schedule 10, as well as the 
flexibility afforded public utility transmission providers to design 
services relevant to recover all costs associated with the integration 
of VERs under proposed Schedule 10.\265\ For example, while EEI 
indicates that it supports the establishment of a cost recovery 
mechanism for regulation reserves from transmission customers as 
promoting rate certainty and transparency, it also cautions the 
Commission that the proposal may unduly condition cost recovery and may 
not encompass all cost incurred by the transmission provider. While 
Independent Power Producers Coalition--West supports the concept of a 
generic generator imbalance tariff to bring certainty to disparate 
tariffs that must now be negotiated in WECC, it contends that the 
Commission should require utilities to revise operating agreements, 
business practices or other procedures such that independently owned 
generator resources are available to balancing authorities in the WECC 
to reduce generator imbalance costs for VERs. Large Public Power 
Council supports the new Schedule 10 provided it is implemented in a 
way that allows transmission providers to receive full compensation for 
providing the service.
---------------------------------------------------------------------------

    \265\ CMUA at 10-11; EEI at 25-33; Midwest ISO at 14; NRECA at 
23-24; Organization of Midwest ISO States at 8-9.
---------------------------------------------------------------------------

    245. NRECA indicates that it also supports the cost recovery 
proposal embodied in proposed Schedule 10; however, it expresses 
concern that Schedule 10 should not be limited to just the recovery of 
regulation costs, and should instead be expanded to allow public 
utility transmission providers the opportunity to demonstrate that 
additional VER integration costs should be recovered through individual 
Schedule 10s. According to NRECA, such costs may include the following: 
(1) Intra-hour schedule implementation costs; (2) power production 
forecasting implementation costs; or (3) other various costs such as 
load-following service, ramping costs, out-of-merit dispatch costs, and 
additional spinning and supplemental reserves, among other things.
    246. Public Power Council and Puget express similar concerns that 
the proposed Schedule 10 would not allow for full recovery of all costs 
of balancing and integrating VERs. According to Public Power Council, 
Schedule 3 recovers the costs of balancing reserves deployed for 
frequency and regulation control, which in turn leads Schedule 10 to 
only recover the costs of regulation (capacity following near 
instantaneous changes in generation) but not the costs arising from 
either load following capacity (capacity used minute-to-minute over 
approximately a 10-minute period) or capacity needed to make up a 
variable generator's schedule error for the scheduling period. Public 
Power Council also argues that Schedule 10 charges should include the 
costs of power production forecasting systems as these would not be 
needed but for the integration of variable generation. The PNW Parties 
agree and suggest that Schedule 10 should be expanded further to allow 
for the recovery of all costs incurred by the public utility 
transmission provider in providing regulating reserves that are not 
recoverable through the generation imbalance rate, including but not 
limited to, extra energy costs and operation and maintenance costs.
    247. Southern states that the capacity required to provide 
generator imbalance service or otherwise respond to operational 
challenges presented by substantial swings in output from generators 
(particularly VERs) may mostly be conceptualized as providing a 
``regulation'' service, but it should be understood that some public 
utility transmission providers may also incur additional costs that may 
implicate other ancillary services, such as reactive power and load 
following, if not contingency response. Southern asserts that the 
Commission should not categorically foreclose or limit in advance the 
right of public utility transmission providers under section 205 to 
file tariffs or tariff amendments on a case-by-case basis to recover 
any and all additional reasonable costs specific to VER-related 
regulation reserve requirements. Southern requests that the Commission 
confirm that the invitation in Order No. 890 for public utility 
transmission providers to file rate schedules and amendments to address 
costs of generator imbalances on a case-by-case basis remains open.
    248. Public Interest Organizations contend that it may be unjust 
and unreasonable to charge VERs regulation rates for capacity 
requirements that can be addressed by less expensive ancillary 
services. Public Interest Organizations state that the Commission could 
address this problem either by reforming Schedule 10 into a slower 
service akin to load-following or non-spinning reserves, or by 
clarifying that Schedule 10 is designed to compensate only for the 
moment-to-moment balancing associated with generation variability, and 
not for VER variability that affects the system beyond the balancing 
timeframe.
    249. AWEA suggests that the Commission focus on such longer-term 
variability, requesting that the Commission reformulate proposed 
Schedule 10 as a system non-spinning service to accommodate the 
aggregate system variability that is not accommodated through other 
ancillary services. AWEA states that this type of service would benefit 
all users of the system by providing inexpensive reserves to 
accommodate all types of gradual variability on the power system, 
including changes driven by inaccurate

[[Page 41522]]

load forecasts, changes in demand driven by large electricity users, as 
well as aggregate changes of many small users. AWEA notes that wind and 
solar exhibit little variability over the regulation time period while 
variability over the course of an hour can be more significant. AWEA 
argues that a system non-spinning service would be well-suited for 
accommodating the incremental increase in system variability caused by 
the addition of such resources.
    250. Similarly, Iberdrola recommends the Commission structure 
Schedule 10 as a following reserves service rather than regulation 
reserve, arguing that the rate of change associated with wind ramps is 
not instantaneous but rather occurs over longer time periods within the 
hour and often for multiple hours. To the extent that the Commission 
does not reformulate Schedule 10 in this way, Iberdrola requests that 
the Commission convene a technical conference that focuses on the 
ancillary services needed to support VERs. NextEra agrees that the 
Commission should convene a technical conference to address what kind 
of ancillary services should be developed to complement the growth of 
VERs, among other things.
    251. Duke suggests that the Commission should unbundle regulation 
and frequency response service into separate ancillary service 
schedules. In support, Duke points to such industry activities as NERC 
developing a revision to Frequency Response Reliability Standard BAL-
003-0, which will prescribe specific amounts of frequency response that 
each balancing authority must procure; the Commission report prepared 
by the Lawrence Berkeley National Laboratory, which discusses 
operational characteristics and distinctions of primary and secondary 
frequency control reserves (Docket No. AD11-8-000); and the 
Commission's Notice of Proposed Rulemaking in Docket Nos. RM11-7-000 
and AD10-11-000, which also distinguishes frequency response from 
regulation.
    252. American Clean Skies argues that the Proposed Rule should 
require RTOs to offer additional ancillary services, such as load 
following (on a minute-to-minute basis), reactive power and other 
comparable backup capabilities. Coalition for Green Capital similarly 
asks the Commission to encourage the development of power and ancillary 
services products that match the technical and commercial capabilities 
of VERs to allow VERs to integrate into the bulk power grid at rates 
and on terms and conditions that are just and reasonable and not unduly 
discriminatory or preferential. Independent Energy Producers assert 
that, while it is critical that ancillary service products be 
identified and developed to permit VERs to be integrated, it is equally 
critical that the necessary compensation measures be developed to 
ensure that dispatchable generation is available when and where it is 
needed to support the ancillary services products, particularly within 
the California ISO market.
    253. With regard to charging transmission customers under both 
Schedule 3 and the proposed Schedule 10, Bonneville Power agrees with 
the Commission's decision in Order No. 890 regarding the potential for 
double recovery if energy settlement charges (under Schedules 4 and 9 
of the OATT) are imposed on both the generator and load when they 
reside in the same balancing authority, but argues that there are 
significant differences between energy settlement charges and capacity 
charges recovered under Schedule 3 and Proposed Schedule 10. Bonneville 
Power states that the public utility transmission provider must 
maintain balancing reserve capacity for movement of both the load and 
the generators located in its balancing authority area because the 
deviations from schedule for the load and generation move independently 
from one another, and that the transmission provider should be allowed 
to recover costs for capacity it is providing to both generation and 
load.
    254. Duke similarly argues that the Commission should allow the 
public utility transmission provider to recover both Schedule 3 and 10 
costs if both services are utilized by the transmission customer. Duke 
contends that it is appropriate in some circumstances to charge a load 
for Schedule 3, and a generator for Schedule 10, even if they are owned 
by the same party. According to Duke, unless the generator is coupled 
to the load by an energy management system (i.e., the generator is 
controlling to the load), or the generator is dynamically serving a 
load (i.e., where its output can be controlled to match the load it 
serves), a public utility transmission provider should be permitted to 
charge for both Schedule 3 and Schedule 10 as they are two different 
services which can be provided at the same time (e.g., where a load 
serving entity owns load within a control area, as well as a 
generator).
    255. Finally, several commenters contend that Schedule 10 is not 
necessary in organized markets.\266\ PJM interprets Schedule 10 as 
optional and seeks clarification that this interpretation is correct. 
Sunflower and Mid-Kansas submit that the SPP market rules already are 
consistent with or superior to the pro forma OATT as the Commission 
proposed to amend it in the Proposed Rule and believes it is highly 
likely that all of the other RTOs' rules are also superior to what has 
been proposed. Clean Line contends that the potential of double 
recovery exists for generators receiving compensated through organized 
market mechanisms. AWEA contends that the Commission should clarify 
that the creation of Schedule 10 service should apply only in areas of 
the country that do not have functioning ancillary services markets. 
Likewise, Iberdrola explains that a Schedule 10-type product is not 
necessary in organized markets, as most organized markets balance the 
system's energy and reserve requirements through use of simultaneously 
co-optimized Security Constrained Unit Commitment and Security 
Constrained Economic Dispatch algorithms that clear and dispatch energy 
and reserves.
---------------------------------------------------------------------------

    \266\ E.g., AWEA; California ISO; Iberdrola; ISO New England, 
New York ISO; Sunflower and Mid-Kansas.
---------------------------------------------------------------------------

ii. Obligation To Offer Generator Regulation Service
    256. Several commenters seek clarification regarding the extent to 
which the public utility transmission provider must provide generator 
regulation service. NaturEner states that public utility transmission 
providers should not be able to avoid providing regulating reserves 
based upon claims that they themselves do not own generation in 
sufficient amounts to supply the service. Xtreme Power asks that the 
Commission make clear that, in the event that a public utility 
transmission provider's existing resources are not adequate to meet the 
obligation to provide generator regulation service and new resources 
are needed to accommodate additional variability, the public utility 
transmission provider is obligated to procure a sufficient quantity of 
the appropriate resources.
    257. Grant PUD asks whether a public utility transmission provider 
must procure additional regulation resources if the demand for these 
services exceeds the contractual and owned resources available to the 
public utility transmission provider that can provide regulation 
service at the time of the request for service. NorthWestern requests 
that the Commission clarify

[[Page 41523]]

that the phrase ``or from resources available to it'' refers to 
acquisition of generator regulation service from third parties and is 
not intended to mean that, if the utility does not have access to its 
own resource or resources from the market, the utility must build 
generation for Schedule 10 service. Independent Power Producers 
Coalition--West states that transmission providers should not be 
permitted to charge VERs for generator imbalance services unless they 
provide VERs with the capability to obtain those services from third 
parties on a non-discriminatory basis. If a public utility transmission 
provider does not have access to its own resources or resources from 
the market and chooses to build new generation to offer Schedule 10 
service, EEI asks the Commission to clarify that these costs can be 
recovered from the resources that trigger the need to build. EEI also 
states that the language ``or from resources available to it'' could be 
read to require the public utility transmission provider to violate 
reliability standards by using resources set aside for contingency 
reserves to support generation regulation service.\267\ EEI requests 
that the Commission clarify the statement as follows: ``a public 
utility transmission provider must offer generator regulation service; 
to the extent it is physically feasible to do so from its existing 
resources or from resources currently available to it, without 
violating applicable reliability standards.'' \268\
---------------------------------------------------------------------------

    \267\ EEI at 32.
    \268\ Id.
---------------------------------------------------------------------------

    258. Puget asks that the Commission clarify that public utility 
transmission providers are only required to provide Schedule 10 service 
within a defined confidence interval commensurate with the public 
utility transmission provider's level of regulation capacity set aside 
for cost recovery under the Schedule 10. If those resources' 
capabilities are exceeded or if system conditions otherwise warrant, 
Puget suggests that the public utility transmission provider should 
retain the right to curtail generation production or export schedules 
to preserve reliability. Public Power Council and Bonneville Power also 
question whether the obligation to provide generator regulation service 
is unlimited, suggesting that such service could require firming of 
every generation delivery, which would be extremely expensive. 
Bonneville Power contends that the source balancing authority should 
have the ability to offer a base level quantity of balancing reserve 
capacity and should have the right to use operational tools to limit 
the deployment of reserves to that quantity. In support, Bonneville 
Power explains that it has developed Dispatcher Standing Order 216 (DSO 
216) to require reductions in wind generation or changes to wind 
generators' transmission schedules when the schedule error of the wind 
fleet exhausts the total amount of balancing reserve capacity that 
Bonneville Power has made available for wind and load.
    259. Bonneville Power states that it is currently providing enough 
balancing reserve capacity to meet the needs of the wind fleet in its 
balancing authority during 99.5 percent of the forecast VER variability 
events. Bonneville Power describes the remaining 0.5 percent as 
representing the most extreme variability in VER generation (i.e., 
``tail events''). Because of the substantial wind generation exports 
from Bonneville Power's balancing authority area, Bonneville Power 
explains that it needs a mechanism to ``clip the tails'' of wind ramps 
when they exhaust the total amount of balancing reserve capacity that 
Bonneville Power makes available for wind and load. Bonneville Power 
states that DSO 216 allows it to establish the amount of balancing 
reserve capacity that will be deployed and, because there is a set 
limit, it is able to quantify its obligation and risks for rate 
setting, system planning, and reliability purposes. Bonneville Power 
contends that a requirement to maintain balancing reserve capacity at 
all times to manage tail events would be significantly expensive.
    260. Bonneville Power also asks the Commission to clarify that the 
public utility transmission provider is required to offer to provide 
Schedule 10 service only to the extent it can do so without harming 
system reliability or risking non-compliance with state and Federal law 
and other non-power requirements that affect system operations. 
Snohomish County PUD and Grays Harbor PUD similarly ask the Commission 
to clarify that Bonneville Power should not be required to offer 
capacity from the Federal System to meet demand for services under 
Schedule 10 where that capacity is not available due to statutory and 
regulatory obligations that limit the availability of the Federal 
System's capacity. Grays Harbor PUD adds that the Commission should 
make clear that, during periods when Bonneville Power's system is 
limited by statutory and regulatory constrains, it is not ``physically 
feasible'' for Bonneville Power to use that capacity to support 
integration of VERs and, therefore, during those periods is exempt from 
requirements to do so. Bonneville Power further requests that the 
Commission clarify that the public utility transmission provider is 
obligated to provide generator regulation service pursuant to Schedule 
10 and generator imbalance service pursuant to Schedule 9 only to the 
extent that balancing reserve capacity is made available pursuant to 
Schedule 10. In addition, Bonneville Power suggests that the Commission 
should address the pricing policy articulated in the Avista line of 
cases, which restricts public utility transmission providers that are 
not in organized markets to recovering cost-based rates for ancillary 
services, to ensure public utility transmission providers have the 
ability to obtain the necessary balancing reserve capacity.\269\ Tres 
Amigas concurs with Bonneville Power and suggests that the Commission 
alter its approach so that these services can be bought and sold 
competitively outside of organized RTO markets as they are in most 
RTOs.
---------------------------------------------------------------------------

    \269\ Bonneville Power (referencing Avista Corp., 87 FERC ] 
61,223 (1999); Market-Based Rates For Wholesale Sales Of Electric 
Energy, Capacity And Ancillary Services By Public Utilities, Order 
No. 697, 119 FERC ] 61,295 (2007) (Order No. 697)).
---------------------------------------------------------------------------

iii. Self-Supply of Generator Regulation Service
    261. First Wind asks the Commission to clarify that Schedule 10 
charges would be imposed on VERs only to the degree they take 
transmission service or otherwise elect to take Schedule 10 service. 
AEP contends that the Proposed Rule contains a loophole in that 
purchasers of VER energy outside of the resource's native balancing 
authority's footprint would be able to avoid any ancillary service 
charges caused by their purchase and transport of energy. Other 
commenters discuss how the balancing authority into which generation is 
dynamically scheduled would be compensated for providing regulation 
service.\270\ These commenters contend that because the sink balancing 
authority is providing the regulation service for that generator in 
these situations, it should be clear in Schedule 10 that the sink 
balancing authority will be paid for providing that service.
---------------------------------------------------------------------------

    \270\ E.g., Duke; EEI; Exelon.
---------------------------------------------------------------------------

    262. Commenters address the option for transmission customers to 
self-supply generator regulation service. Bonneville Power states that 
it recognizes that VERs may find it economical to self-supply balancing 
reserve capacity to provide balancing service and asks the Commission 
to clarify in Schedule 10 that a customer electing to self-supply is 
subject to the public utility transmission provider's requirements for 
Schedule 10 service

[[Page 41524]]

and the transmission provider's reliability and operational protocols, 
including any transmission curtailments and generation limitations in 
the event the self-supplying VER fails to meet the transmission 
provider's standards. Powerex agrees that the public utility 
transmission provider should have discretion to decide whether a method 
of self-supply is acceptable but argues that the public utility 
transmission provider should be required to describe what it considers 
to be acceptable comparable arrangements in posted business practices.
    263. Xtreme Power similarly contends that, in order for self-supply 
or third-party procurement of generator regulation service to be a 
viable option, the public utility transmission provider must specify 
how a customer's generator regulation service requirements are 
determined and how the requirements may be satisfied through self-
supply or third-party procurement. NaturEner contends that the self-
supply provision should be administered on a flexible basis and this 
could include use of self-curtailment, carrying of a portion of the 
regulating reserve capacity on a dynamic basis, and carrying of a 
varying level of regulating reserves because a constant level is not 
necessary. Independent Power Producers Coalition--West argues that 
public utility transmission providers should only be permitted to 
charge VERs for generator imbalance services if they provide VERs with 
the capability to obtain those services from third parties on a non-
discriminatory basis.
    264. Beacon Power indicates that entities subject to Schedule 10 
should be allowed to work with public utility transmission providers in 
non-RTO/ISO markets to determine different volumes of self-supplied 
regulation reserve capacity required based on the ramp-rate capability 
of its regulation resource(s). CESA agrees that, if a transmission 
customer subject to the Schedule 10 chooses to self-supply its 
regulation reserve capacity, the amount of capacity self-supplied 
should account for the fact that a MW of reserve capacity from a fast-
ramping resource provides more regulation value to the grid per MW than 
a slow-ramping resource. NEMA indicates that some resources that 
provide generator regulation service, such as batteries and flywheels, 
can dampen variations much more quickly than can traditional 
generators. Therefore, NEMA contends that the generator regulation 
service requirements should be based on the amount of generator 
regulation service actually provided, rather than solely the capacity 
of regulation service. A123 recommends that the Commission clarify the 
phrase ``alternative comparable arrangements'' to include resources 
that may differ in MW capacity but supply equivalent or superior 
regulation performance when compared to the public utility transmission 
provider's default service.
    265. Powerex asks that the Commission confirm that self-supply 
includes the ability of the transmission customer to self-supply by 
purchasing regulation reserve capacity from third parties.\271\ Powerex 
states that it could be helpful for the Commission to provide guidance 
on what should qualify as an ``alternative comparable arrangement.'' 
SEIA supports providing transmission customers with the opportunity to 
avoid regulation service costs through dynamic scheduling or self-
supply arrangements, but ask the Commission to clarify how self-supply 
would allow solar plants to avoid regulation reserve requirements, 
which SEIA believes would assign a constantly varying share of the 
Schedule 10 requirement to a solar plant capable of providing 
regulation service. The Federal Trade Commission asserts that the self-
supply option under Schedule 10 is vague and should recognize that VERs 
could address their regulation requirements by matching their 
generation variability to demand variability.
---------------------------------------------------------------------------

    \271\ Powerex at 22.
---------------------------------------------------------------------------

    266. Other commenters request that additional requirements be 
included in Schedule 10 with regard to self-supply. CGC states that the 
Proposed Rule fails to require public utility transmission providers to 
provide dynamic transfer capability out of their balancing authority 
area or provide an ancillary services market through which a generator 
could self-supply generator regulation service. CGC asks the Commission 
to require all public utility transmission providers, either by 
themselves or in association with other public utility transmission 
providers, to provide access to a fully functioning competitive 
ancillary services market and/or dynamic transfer capabilities. ELCON 
asserts that the Commission should specify that public utility 
transmission providers must consider using dispatchable demand response 
resources to provide Schedule 10 service. CESA recommends that FERC 
allow Schedule 10 self-supply requirements to vary based on the ramp-
rate of the resources providing the service, offering that faster-
acting resources provide more ACE correction than slower resources.
c. Commission Determination
    267. The Commission declines to amend the pro forma OATT to include 
a standardized ancillary services schedule for generator regulation 
services as proposed in the Proposed Rule. As indicated above, the 
Commission intended for proposed Schedule 10 to be a clearly defined 
mechanism for public utility transmission providers to recover the 
costs of capacity held in reserve to provide generator imbalance 
service under Schedule 9 of the pro forma OATT, while also providing 
customers with certainty as to the rates they will be required to pay 
when taking this service. The Commission also sought to confirm the 
right of public utility transmission providers to recover the 
reasonably incurred costs of providing this capacity service and to 
distinguish, where appropriate, among classes of customers who cause 
such costs to be incurred.
    268. In response to the Proposed Rule, the Commission received 
numerous comments urging flexibility in the design of capacity services 
needed to integrate VERs into transmission systems, suggesting that the 
proposed pro forma generator regulation service may not be the most 
efficient and economical service with which to integrate VERs. For 
example, Southern notes that the recovery of capacity costs incurred to 
provide Schedule 9 generator imbalance service could implicate a range 
of services, from regulation to load following, depending on how the 
public utility transmission provider conceptualizes the service 
provided. Iberdrola suggests that VER integration has more significant 
implications for within hour spinning and non-spinning capacity than 
moment-to-moment regulation capacity. In light of these comments, the 
Commission concludes that the adoption of a standardized pro forma 
Schedule 10 could inhibit the flexibility commenters seek to design 
capacity services that align with the operational needs of a particular 
public utility transmission provider. Accordingly, the Commission 
declines to adopt the proposed Schedule 10 component of the Proposed 
Rule and will continue to evaluate proposals to recover capacity costs 
incurred to provide Schedule 9 generator imbalance service on a case-
by-case basis. In this way, public utility transmission providers will 
remain free to propose capacity services that best respond to the needs 
of their customers and will not have to expend resources adopting the 
one-size-fits-all generator regulation service discussed in the

[[Page 41525]]

Proposed Rule, even in situations where some other service or rate 
design may be more appropriate.
    269. To be clear, the Commission emphasizes that our decision not 
to implement a generic rate schedule for generator regulation service 
should not be interpreted as an unwillingness to consider individual 
proposals brought by public utility transmission providers. The 
Commission recognizes that a public utility transmission provider may 
incur capacity costs associated with fulfilling obligations to provide 
Schedule 9 generator imbalance service and that existing rate 
mechanisms may be inadequate for some public utility transmission 
providers to properly allocate and recover those costs. For many years, 
the Commission has evaluated proposals to recover such capacity costs 
on a case-by-case basis in light of the specific facts and 
circumstances in each case.\272\ The Commission concludes that 
continuation of this case-by-case approach is more appropriate to 
tailor the particular capacity services needed by a public utility 
transmission provider to its operations. At the same time, the 
Commission is sensitive to commenter requests to provide guidance 
regarding the proper design of a generator regulation service charge 
should a public utility transmission provider desire to propose one. In 
the section that follows, the Commission provides a framework that can 
be used for those public utility transmission providers seeking to 
develop a proposal to recover capacity costs incurred to provide 
Schedule 9 generator imbalance service.\273\
---------------------------------------------------------------------------

    \272\ See Florida Power Corp., 89 FERC ] 61,263, at 61,765 
(1999) (Florida Power) (``The Commission concludes that a generator 
imbalance capacity obligation is imposed on the transmission 
provider for export transactions, and therefore the Commission 
accepts Florida Power Corp's Generator Regulation Service as a 
reasonable proposal in those circumstances where the service is not 
already covered in an interconnection agreement or a separate 
generator tariff.''); Entergy, 120 FERC ] 61,042 at PP 62-66 
(accepting a generator regulation service rate schedule for 
independent power producers selling out of the control area that 
retained charges that had been previously negotiated between Entergy 
and the relevant independent power producers); Sierra Pac. Res. 
Operating Cos., 125 FERC ] 61,026, at P 10 (2008) (accepting a 
generator regulation service rate schedule to provide the capacity 
necessary to follow the moment-to-moment changes caused by 
generators selling outside of the transmission provider's control 
area).
    \273\ See infra Sec.  IV.C.2 (Mechanics of a Generator 
Regulation Charge). While this section is framed primarily in terms 
of a generator regulation service, the principles discussed would 
also apply more broadly to other capacity services designed to 
recover capacity costs incurred to provide Schedule 9 generator 
imbalance service.
---------------------------------------------------------------------------

    270. Before turning to the mechanics of a generator regulation 
service charge, the Commission clarifies in response to comments that 
our decision not to adopt a generic Schedule 10 does not relieve public 
utility transmission providers of obligations under the pro forma OATT 
to provide Schedule 9 generator imbalance service. This in turn 
requires the public utility transmission provider to maintain 
sufficient capacity to provide that service.\274\ However, as the 
Commission explained in Order No. 890-A, if it is not physically 
feasible for a transmission provider to offer generator imbalance 
service using its own resources, either because they do not exist or 
they are fully subscribed, the public utility transmission provider 
must attempt to procure alternatives to provide the service, taking 
appropriate steps to offer an option that customers can use to satisfy 
their obligation to acquire generator imbalance service as a condition 
of taking transmission service.\275\ The Commission explained that each 
transmission provider can state on its OASIS the maximum amount of 
generator imbalance service it is able to offer from its resources, 
based on an analysis of the physical characteristics of its system. 
Alternatively, a public utility transmission provider may consider 
requests for generator imbalance service on a case-by-case basis, 
performing, as necessary, a system impact study to determine the 
precise amount of additional generation it can accommodate and still 
reliably respond to the imbalances that could occur.\276\
---------------------------------------------------------------------------

    \274\ NorthWestern Corp., 129 FERC ] 61,116, at P 24 (2009), 
order denying reh'g, 131 FERC ] 61,202, at PP 17-18 (2010).
    \275\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at PP 289-
90.
    \276\ Id. P 289.
---------------------------------------------------------------------------

    271. Because a proposal for generator regulation service would be 
associated with generator imbalance service, it follows that the public 
utility transmission provider would use a similar analysis to identify 
any limitations on its ability to offer either service.\277\ Just as it 
can for generator imbalance service, the public utility transmission 
provider could explain on its OASIS the maximum amount of generator 
regulation service it is able to offer after having attempted to 
procure alternative resources to provide the service. Alternatively, 
the public utility transmission provider could perform a system impact 
study to determine the precise amount of generator regulation service 
it can provide. In response to NorthWestern, this Final Rule does not 
place any obligation on the public utility transmission provider to 
build generation.
---------------------------------------------------------------------------

    \277\ In the unlikely event that there are no additional 
resources available to enable the public utility transmission 
provider to meet its obligation to offer generator regulation 
service, the public utility transmission provider must accept the 
use of dynamic scheduling with a neighboring control area. See id. P 
290.
---------------------------------------------------------------------------

    272. With regard to comments regarding self-supply of ancillary 
services, the Commission acknowledges that self-supply may come from 
many sources, including purchased capacity and the use of non-
generation resources, as suggested by ELCON. The option to self-supply 
certain ancillary services has been in place since Order No. 888, and 
the Commission declines here to specify any particular requirements for 
self-supply arrangements for generator regulation service proposals. To 
do so could restrict flexibility to develop competitively priced 
options tailored to particular customer needs. As suggested by some 
commenters, such options could include the use of faster ramping 
resources to provide the service.
    273. In response to Powerex, the Federal Trade Commission and 
others, the Commission does not believe that the self-supply option is 
vague or that additional guidance is necessary on what should qualify 
as an ``alternative comparable arrangement.'' The Commission notes that 
public utility transmission providers already are obligated to post on 
their public Web sites all rules, standards, and practices, to the 
extent they exist, that relate to transmission service.\278\ The 
provision of ancillary services is necessary to accomplish transmission 
service and, therefore, we conclude this posting obligation applies 
equally to ancillary services.\279\ Public utility transmission 
providers must post any rules, standards, and practices regarding self-
supply requirements pursuant to their obligation to allow self-supply 
of ancillary services.\280\ The Commission declines to adopt further 
requirements at this time regarding the self-supply of ancillary 
services.\281\
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    \278\ Order No. 890, FERC Stats.& Regs. ] 31,241 at P 1652.
    \279\ The Commission notes that this obligation is subject to 
audit as are all other OATT requirements.
    \280\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,705.
    \281\ Id.
---------------------------------------------------------------------------

    274. In response to the Federal Trade Commission, the Commission 
encourages transmission providers, generators, and transmission 
customers to work together to explore options to find the least cost 
methods of balancing the system as a whole and to provide maximum 
flexibility for products and services that meet the needs of the 
customers and the transmission

[[Page 41526]]

providers alike. This includes, for example, evaluating the extent to 
which regulation service obligations can be addressed by matching 
generation variability to demand variability, as suggested by the 
Federal Trade Commission. Indeed, in Order No. 888, the Commission 
stated that the pricing of ancillary services should include the amount 
of each ancillary service that the transmission customer must purchase, 
self-supply, or otherwise procure and must be readily determinable from 
the transmission provider's tariff and comparable to obligations to 
which the transmission provider itself is subject.\282\ The Commission 
also specified that the transmission provider is required to identify 
the regulating margin requirements for transmission customers serving 
loads in its balancing authority area and to develop procedures by 
which customers can avoid or reduce such requirements.\283\
---------------------------------------------------------------------------

    \282\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,721.
    \283\ Id. at 31,717. Order No. 890 did not alter the 
requirements of Order No. 888 in this regard, but did clarify that 
regulation and frequency response, as well as imbalance energy, may 
be provided by public utility transmission providers or through 
self-supply using generating units as well as other non-generation 
resources such as demand resources where appropriate. Order No. 890, 
FERC Stats. & Regs. ] 21,241 at P 888.
---------------------------------------------------------------------------

    275. For reasons explained elsewhere in this Final Rule, the 
Commission declines to adopt CGC's suggestion to require transmission 
providers to provide dynamic transfer capability out of their balancing 
authority area or mandate the creation of an ancillary services market 
through which a generator could self-supply generator regulation 
service.\284\
---------------------------------------------------------------------------

    \284\ See supra IV.A.1 (Intra-Hour Scheduling Requirement).
---------------------------------------------------------------------------

2. Mechanics of a Generator Regulation Charge
    276. The Proposed Rule stated that, as with Schedule 3, the 
proposed Schedule 10 charge would be the product of two components: a 
per-unit rate for regulation reserve capacity, and a volumetric 
component for regulation reserve capacity.\285\ The Commission proposed 
to require each public utility transmission provider to submit a 
compliance filing that includes the addition of a Generator Regulation 
and Frequency Response rate schedule to the OATT that includes the same 
per unit rate from their currently effective Regulation and Frequency 
Response rate schedule and a blank or unfilled volumetric 
component.\286\
---------------------------------------------------------------------------

    \285\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 92. The 
Commission is exploring potential reforms to ancilliary services 
pricing in other proceedings. See Third-Party Provision of Ancillary 
Services; Accounting and Financial Reporting for New Electric 
Storage Technologies, Notice of Proposed Rulemaking, 139 FERC ] 
61,245 (2012) (NOPR).
    \286\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 101.
---------------------------------------------------------------------------

    277. The Commission preliminarily found that the per-unit rate for 
service under proposed Schedule 10 should be the same as the rate for 
service under existing Schedule 3.\287\ The Commission explained that 
Schedule 3 and the proposed Schedule 10 are both designed to recover 
the costs of holding regulation reserve capacity to meet system 
variability. Because the service provided under both schedules is 
functionally equivalent, the Commission proposed to find that it is 
just and reasonable to use the same rate currently established in a 
public utility transmission provider's Schedule 3 when charging 
transmission customers under Schedule 10. The Commission stated that, 
for a public utility transmission provider to apply a different rate 
under the proposed Schedule 10, the public utility transmission 
provider would have to demonstrate that the per-unit cost of regulation 
reserve capacity is somehow different when such capacity is utilized to 
address system variability associated with generator resources. The 
Commission also noted that the use of a common rate is consistent with 
Commission policy utilizing the same rate structure for energy and 
generator imbalance service, as well as the generator regulation rate 
that the Commission accepted in Westar Energy Inc.\288\
---------------------------------------------------------------------------

    \287\ Id. P 94.
    \288\ Id. P 93 (citing Westar Energy Inc., 130 FERC ] 61,215 
(2010) (Westar)).
---------------------------------------------------------------------------

    278. With regard to the volumetric component of the Schedule 10 
rate, the Commission proposed to provide each public utility 
transmission provider with the opportunity to justify a proposal: (1) 
To require all transmission customers who are delivering energy from 
generators to purchase, or otherwise account for, the same volume of 
generator regulation reserves; or (2) to require transmission customers 
who are delivering energy from VERs to purchase, or otherwise account 
for, a different volume of generator regulation reserves than it 
proposes to charge transmission customers delivering energy from other 
generating resources.\289\ The transmission provider's proposal would 
be made in a section 205 filing after the acceptance of its compliance 
filing.
---------------------------------------------------------------------------

    \289\ The Commission noted its expectation that, in any 
subsequent filing to establish a volumetric component in Schedule 
10, public utility transmission providers would address how Schedule 
10 and Schedule 3 work together to allow for the recovery of total 
regulation reserve costs. Id. P 105 & n.206.
---------------------------------------------------------------------------

    279. Where a public utility transmission provider proposes the same 
volume of generator regulation reserves for all generators, the 
Commission proposed that it demonstrate that the volume of regulation 
reserves required of transmission customers delivering energy from 
generators located within its balancing authority area be commensurate 
with their proportionate effect on net system variability, taking 
account of diversity benefits.\290\ The Commission stated that such a 
filing must show that the public utility transmission provider has 
fully implemented (or been granted waiver from) the intra-hourly 
scheduling requirement set forth in the Proposed Rule.\291\ The 
Commission recognized that a public utility transmission provider with 
few VERs located in its balancing authority area may choose to apply 
only one volumetric regulation requirement for all generating resources 
in its balancing authority area. The Commission noted that this also 
may be the case to the extent the impact of VERs on a public utility 
transmission provider's system is minimal and the public utility 
transmission provider, in its judgment, deems the administrative burden 
of justifying two separate volumetric regulation requirements is 
uneconomic.\292\
---------------------------------------------------------------------------

    \290\ The Commission explained that diversity benefits result 
from the aggregation of the variations of all resources such that 
one resource's negative deviation can offset some or all of another 
resource's positive deviation. The Commission stated that, when the 
transactions of two customers result in diversity benefits, it is 
incorrect to say that one customer is benefitting the other but not 
vice versa. Instead, the Commission preliminarily found that 
diversity benefits would result from both transactions and that 
sharing of these benefits among the customers would be reasonable. 
Westar,130 FERC ] 61,215 at P 37.
    \291\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 105.
    \292\ Id. P 94.
---------------------------------------------------------------------------

    280. The Commission proposed that where a public utility 
transmission provider proposes to require transmission customers who 
are delivering energy from VERs to purchase, or otherwise account for, 
a different volume of generator regulation reserves than it proposes to 
charge transmission customers delivering energy from other generating 
resources, the Commission proposed that it demonstrate that the volumes 
of regulation reserves required of those subsets of transmission 
customers delivering energy from generators located within its 
balancing authority area are commensurate with their proportionate 
effect on net system

[[Page 41527]]

variability and taking account of diversity benefits.\293\ That is, any 
proposal for different volumes of generator regulation reserves based 
on the generating resource would need to be supported by data showing 
that, on the public utility transmission provider's system, VERs have a 
different per unit impact on overall system variability than 
conventional generating units.\294\ The Commission proposed that such a 
filing must also show that the public utility transmission provider has 
fully implemented (or been granted waiver from) the intra-hourly 
scheduling requirement set forth in the Proposed Rule and has developed 
and deployed power production forecasting for VERs.\295\
---------------------------------------------------------------------------

    \293\ Id. P 106.
    \294\ Id. P 95.
    \295\ Id. P 106.
---------------------------------------------------------------------------

    281. Specifically, the Commission proposed that any filing by 
public utility transmission providers including different volumetric 
requirements for different subsets of transmission customers must be 
supported with actual data collected over a one-year period subsequent 
to the deployment of power production forecasting for VERs and the 
implementation of intra-hourly scheduling at 15-minute intervals. The 
Commission acknowledged that this proposal could delay a public 
utility's ability to recover the cost associated with providing 
generator regulation service. The Commission further acknowledged that 
there may be alternative methods for developing the data necessary to 
support different volumetric requirements for different subsets of 
transmission customers. The Commission sought comment as to such 
methods of demonstration, how they could support a Commission finding 
that the Schedule 10 filing is just and reasonable, and ways in which 
these methods of demonstration may be preferable to this aspect of the 
Commission's proposal.\296\
---------------------------------------------------------------------------

    \296\ Id. P 107.
---------------------------------------------------------------------------

    282. In the Proposed Rule, the Commission stated that the increased 
use of power production forecasts in transmission systems where VERs 
are located can provide transmission providers with improved 
situational awareness, enable transmission providers to utilize 
existing system flexibility through the unit commitment and dispatch 
processes, and, ultimately, lead to a reduction in the amount of 
reserve products needed to maintain system reliability. The Commission 
also recognized that, in areas of the country with very limited 
production from VERs, the implementation of power production 
forecasting for VERs could be less useful.\297\ The Commission sought 
comment in the Proposed Rule on the manner by which a public utility 
transmission provider should be required to show it has developed and 
deployed power production forecasts to support a proposal to require a 
differentiated volumetric component of rates for generator regulation 
reserves under proposed Schedule 10.\298\
---------------------------------------------------------------------------

    \297\ Id. P 55 n.125.
    \298\ Id. P 106.
---------------------------------------------------------------------------

a. Comments
i. General
    283. Invenergy Wind requests that the Commission clarify that, in 
requiring initial Schedule 10 charges to adopt the utility's then-
effective Schedule 3 charges, the application of the rate will be 
consistent. Invenergy Wind states that Schedule 3 charges are typically 
applied on the basis of a percentage of the customer's schedule. Beacon 
Power questions the reliance on existing regulation service charges, 
stating that a transmission provider in non-RTO/ISO markets could 
optimize the performance of its existing fleet to potentially lower 
costs to customers under Schedule 3 or 10. Beacon Power requests that 
the Commission encourage such transmission providers to evaluate the 
technologies and benefits they provide. Xtreme Power agrees, asking the 
Commission to require public utility transmission providers to make a 
showing that the rates proposed for Schedule 10 are based on an 
appropriate type and quantity of resources needed, considering the 
technologies available in the market today rather than using dated 
rates from Schedule 3. CESA suggests that the reforms proposed for 
Schedule 3 in the Commission's Frequency Regulation Notice of Proposed 
Rulemaking be included in Schedule 10 for RTO and ISO markets.\299\
---------------------------------------------------------------------------

    \299\ CESA; See also Notice of Proposed Rulemaking on Frequency 
Regulation Compensation in the Organized Wholesale Electric Markets, 
134 FERC ] 61,124 (2010) (Frequency Regulation NOPR); Frequency 
Regulation Compensation in the Organized Wholesale Power Markets, 
Order No. 755, 76 FR 67260 (Oct. 31, 2011), FERC Stats. & Regs. ] 
31,324 (2011), reh'g denied, Order No. 755-A,138 FERC ] 61,123 
(2012).
---------------------------------------------------------------------------

    284. Some commenters suggest that public utility transmission 
providers be permitted to recover opportunity costs associated with 
providing generator regulation service.\300\ For example, the Large 
Public Power Council states that, consistent with the decision in 
Puget, generator regulation service rates should be fully compensatory, 
and may legitimately reflect a utility's full opportunity cost.\301\ 
According to Puget, there may also be lost opportunity costs associated 
with reserving unloaded generation capacity during peak market 
conditions. NRECA argues the integration of a significant amount of 
VERs will cause the Schedule 3 rate to rise as Schedule 10 demand 
increases particularly in regions with a lot of hydropower, where the 
additional VERs cause the need for more thermal reserves, which are 
more expensive than the existing reserve rate base.
---------------------------------------------------------------------------

    \300\ E.g., SMUD; WUTC; EEI; Large Public Power Council; Puget.
    \301\ E.g., Large Public Power Council (citing Puget Sound 
Energy, 132 FERC ] 61,128 (2010)).
---------------------------------------------------------------------------

ii. Quantity of Reserves
    285. Some commenters request further direction from the Commission 
regarding the calculation of the volumetric component of Schedule 10, 
i.e., the quantity of reserves transmission customers are required to 
purchase or otherwise account for.\302\ For example, the California PUC 
asserts that the Commission should recommend or require that a public 
utility transmission provider consider the system's resource mix and 
the amount of operational flexibility of the transmission system's 
generation fleet to develop the volumetric component of Schedule 10. 
LADWP indicates that measures of alleged diversity benefits may lead to 
unintended results if significant diversity occurs in one part of a 
year and forms the basis for a smaller volumetric component than is 
necessary for another part of the year.
---------------------------------------------------------------------------

    \302\ E.g., CPUC; LADWP; SEIA.
---------------------------------------------------------------------------

    286. Some commenters question whether the Commission should allow 
public utility transmission providers the opportunity to file for 
differentiated volumetric rates under Schedule 10. AWEA contends that 
it would be unjust and unreasonable and break with Commission precedent 
to allocate to generators the costs of Schedule 10, whether kept as a 
regulation reserve or reformulated to a system non-spin service, while 
allocating other ancillary services costs broadly to load. AWEA states 
that all users of the grid add variability and uncertainty and that all 
benefit when the grid is better able to accommodate variability and 
uncertainty. AWEA also argues that the capacity used to provide 
Schedule 10 service would be available to provide a number of other 
ancillary services, not to mention to the public utility transmission 
provider to meet peak demand.
    287. Western Grid states that the integration costs of other types 
of generation are largely ignored and the

[[Page 41528]]

regulation and frequency costs imposed by large loads are broadly 
socialized. Western Grid therefore contends that grid integration costs 
related to VERs should be recovered in a manner comparable to the way 
grid integration costs imposed by large conventional generators are 
recovered. Argonne National Lab argues that calculating the net impact 
of VERs on regulation service needs is likely to be difficult and 
contentious and that to ensure just and reasonable treatment of all 
resources, the Commission should be careful in imposing specific 
requirements on VERs without considering the specific impacts on system 
reliability and operating reserve costs from other generating resources 
as well. Similarly, the Federal Trade Commission recommends that the 
Commission consider whether the costs of imbalance services provided to 
other types of generators can readily be identified and charged to the 
responsible parties.
    288. Some commenters support the proposal to condition the 
implementation of differentiated volumetric rates on whether that 
transmission provider has implemented power production forecasting and 
intra-hour scheduling reforms.\303\ AWEA states that Schedule 10 should 
not be charged at all until a transmission provider has fully 
implemented the Efficient Dispatch Toolkit and the Commission's 
proposed sub-hourly scheduling and variable energy forecasting 
operating reforms. Clean Line states that implementation of forecasting 
should be required before any special charges are assigned to renewable 
generators. Clean Line argues that, before transmission providers can 
charge a just and reasonable rate to recover ancillary service costs, 
they must use reasonable means to minimize those costs--such as 
forecasting.
---------------------------------------------------------------------------

    \303\ E.g., AWEA; BP Energy; Iberdrola; Independent Power 
Coalition West; NextEra; Oregon & New Mexico PUC; Public Interest 
Organizations; Vestas.
---------------------------------------------------------------------------

    289. Some commenters suggest that differentiated volumetric rates 
should be conditioned on implementation of additional reforms beyond 
those set forth in the Proposed Rule.\304\ For example, Environmental 
Defense Fund maintains that a public utility transmission provider 
should not be permitted to establish different volumetric reserve 
requirements for VERs unless it has demonstrated to the Commission that 
the balancing authority area is optimally sized or cooperating with 
other balancing authority areas. Oregon & New Mexico PUC similarly 
state that Schedule 10 charges for VERs should be conditioned on a 
demonstration by the public utility transmission provider regarding the 
measures it has considered to increase cooperation with other balancing 
authorities to lower the cost of integrating wind and solar. First Wind 
argues that public utility transmission providers should only be 
permitted to charge for generator regulation service once they have 
implemented procedures for dynamic transfers in addition to intra-hour 
scheduling. CESA contends that, before imposing any generator 
regulation costs on VERs, public utility transmission providers should 
first implement fast intra-hour markets and intra-hourly scheduling; a 
robust ancillary services market; the option for third-party or self 
supply of ancillary services; dynamic transfer capability out of the 
balancing authority area; and Area Control Error (ACE) diversity 
interchange or an energy imbalance service market.
---------------------------------------------------------------------------

    \304\ E.g., Iberdrola; First Wind; Oregon & New Mexico PUC; 
Environmental Defense Fund.
---------------------------------------------------------------------------

    290. In contrast, ELCON asserts that Schedule 10 as proposed is a 
mechanism for the socialization of costs that should be directly 
assigned to VERs or their customers. Grant PUD argues that variable 
loads and variable resources should be charged differently for 
regulation service according to the nature of the different costs 
placed on the public utility transmission provider. A number of other 
commenters agree, objecting to any delay in cost recovery associated 
with providing generator regulation service.\305\ For example, Pacific 
Gas & Electric and Idaho Power argue that public utility transmission 
providers incur costs to provide generator regulation service 
regardless of whether they are employing intra-hourly scheduling and, 
thus, preventing recovery of generator regulation service costs shifts 
those costs to other customers in violation of cost causation 
principles.
---------------------------------------------------------------------------

    \305\ E.g., Tacoma Power; Montana PSC; Pacific Gas & Electric; 
PNW Parties; NV Energy; Public Power Council; Natural Gas; WUTC.
---------------------------------------------------------------------------

    291. EEI opposes requiring a public utility transmission provider 
to commit specific actions before seeking rate recovery under section 
205, particularly when such actions violate cost causation principles. 
EEI states that as articulated by the Commission in Northern States 
Power Company, ``[t]he fundamental theory of Commission ratemaking is 
that costs should be recovered in the rates of those customers who 
utilize the facilities and thus cause the cost to be incurred.'' \306\ 
According to EEI, the D.C. Circuit echoed this sentiment in KN Energy, 
Inc. v. FERC, ``[s]imply put, it has been traditionally required that 
all approved rates reflect to some degree the costs actually caused by 
the customer who must pay them.'' \307\ EEI and others state that, to 
the extent the Commission conditions generator regulation service cost 
recovery on implementing the Proposed Rule's reforms, the Commission 
should explain how such a limitation does not effectively force public 
utility transmission providers to waive their sections 205 and 206 
rights under the FPA in contravention of Atlantic City Electric 
Company.\308\
---------------------------------------------------------------------------

    \306\ EEI at 29 (citing N. States Power Co., 64 FERC ] 61,324, 
at P 13 (1993) (emphasis supplied) (citations omitted)).
    \307\ EEI at 29 (citing KN Energy, Inc. v. FERC, 968 F.2d 1295, 
1300 (D.C. Cir. 1992); Alcoa Inc. v. FERC, 564 F.3d 1342, 1346 (D.C. 
Cir. 2009); Illinois Commerce Commission v. FERC, 576 F.3d 470, 476 
(7th Cir. 2009); Pub. Serv. Comm. of Wisc. v. FERC, 545 F.3d 1058, 
1067 (D.C. Cir. 2008); Pac. Gas & Electric Co. v. FERC, 373 F.3d 
1315, 1320 (D.C. Cir. 2004)).
    \308\ EEI at 27-28 (citing Atlantic City Elec. Co., 295 F.3d 1, 
10 (2002) (finding that the Commission lacks the authority to 
require public utility transmission providers to cede their rights 
under section 205 of the FPA); MidAmerican at 26; Puget at 17 
(questioning whether whether requiring one-year of data reporting 
interferes with a public utility transmission provider's rights 
under section 205 of the FPA); WUCT at 7 (questioning whether 
requiring 15-minute scheduling and one-year of data reporting 
interfere with a public utility transmission provider's rights under 
section 205 of the FPA)).
---------------------------------------------------------------------------

    292. Southern opposes conditioning public utility transmission 
providers' rights to recover rates under section 205 of the FPA for 
generator regulation and frequency response service on the 
implementation of such reforms. Southern argues that utilities have a 
statutory right to establish just and reasonable rates under sections 
205 and 206 of the FPA. If the Commission pursues these limitations, 
Southern asks the Commission to explain how such a limitation does not 
effectively force public utility transmission providers to waive their 
section 205 and 206 rights.
    293. LADWP argues that the proposed requirements would place public 
utility transmission providers in a defensive role. LADWP states that 
presuming a public utility transmission provider makes a sufficient 
showing that it implemented intra-hour scheduling and deployed power 
production forecasting for VERs, a transmission provider is further 
compelled to demonstrate the basis for any difference in regulating 
reserves between VER transmission customers and non-VER transmission 
customers. LADWP argues that this could put the public utility 
transmission providers in a defensive role of justifying the findings 
and conclusions within a system impact study report, in

[[Page 41529]]

the event performed by the public utility transmission provider.
iii. Power Production Forecasting
    294. Some commenters state specific opposition to linking power 
production forecasting to the implementation of differentiated 
volumetric rates under Schedule 10.\309\ Southern argues the Commission 
would exceed its statutory authority if it required implementation of 
power production forecasting. Southern states 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.'' \310\ Southern contends 
that, because the FPA never mentions meteorological forecasting, it is 
beyond the scope of the Commission's authority. Southern explains that 
public utilities have long engaged in meteorological forecasting for 
load forecasting and dispatch purposes; however, 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.
---------------------------------------------------------------------------

    \309\ E.g., Bonneville Power; Montana PSC; Natural Gas; Public 
Power Council; Puget Sound Energy; NV Energy.
    \310\ 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)).
---------------------------------------------------------------------------

    295. While Bonneville Power acknowledges that centralized power 
production forecasts will facilitate system-wide benefits, Bonneville 
Power disagrees that such forecasts should be a prerequisite to the 
cost recovery of balancing reserve capacity used to provide generator 
regulation reserve-type services. Bonneville Power believes that such a 
requirement would shift costs to other users of the transmission system 
that would not be otherwise incurred but for the VER generation. Puget 
believes that requiring transmission providers to implement power 
production forecasting as a precondition to Schedule 10 cost recovery 
inappropriately shifts the costs of integrating VERs from the VER to 
the balancing authority. Southern argues that meteorological 
forecasting issues are business decisions that are best left to the 
transmission providers and the market. EEI states that it is not 
convinced that the power production forecasting requirements are 
necessary to support requiring a higher volumetric amount of Schedule 
10 regulation service. According to EEI, the data necessary to 
substantiate a higher volumetric charge can be derived by analyzing the 
deviation between a VER's scheduled versus actual production. EEI, 
therefore, claims that requiring a public utility transmission provider 
to implement power production forecasting prior to establishing a 
higher volumetric rate creates a barrier to cost recovery.
    296. Montana PSC notes that the Proposed Rule's data reporting 
requirements to support power production forecasting would only apply 
to generators that are 20 MW or larger. Montana PSC argues that 
conditioning differentiation of volumetric rates on the implementation 
of power production forecasting could unduly restrict application of 
Schedule 10 generation regulation charges to smaller resources. Montana 
PSC argues that all VERs one MW or greater should be responsible for 
Schedule 10 services that they cause.
    297. Other commenters ask the Commission to mandate use of power 
production forecasting by all public utility transmission providers 
with significant amounts of VERs instead of relying on the public 
utility transmission owner's decision to charge differentiated Schedule 
10 rates.\311\ The ISO/RTO Council argues that, while transmission 
providers in areas with low to moderate levels of VER interconnection 
may be able to manage variability on their systems without using power 
production forecasting, areas with larger levels of VERs should be 
required to adopt power production forecasting tools to ensure that 
conditions affecting generation output can be anticipated and managed 
appropriately. SEIA suggests that each transmission provider that 
provides interconnection to or has interconnections with more than 50 
MW of VERs should be required to develop a power production methodology 
to accommodate integration of VERs. First Wind contends that power 
production forecasting should be mandatory for public utility 
transmission providers with five percent of VER resources on their 
system. CPUC asks that the Commission clarify that any public utility 
transmission provider may require power production forecasting if VERs 
are currently or anticipated to become significant.
---------------------------------------------------------------------------

    \311\ E.g., CPUC; ISO RTO Council; Midwest ISO; SEIA.
---------------------------------------------------------------------------

    298. Some commenters support the Commission's recognition that 
certain regions may not have a need for VER power production 
forecasting because of a low likelihood of VERs development.\312\ For 
example, Bonneville Power states that the requirement to implement 
centralized forecasting should not apply if the penetration of VERs is 
less than 10 percent of load served. Puget argues that it should not be 
required to use power production forecasting because it only serves one 
exporting VER in its region.
---------------------------------------------------------------------------

    \312\ E.g., Bonneville Power; NextEra; PNW Parties.
---------------------------------------------------------------------------

    299. Several commenters provide detailed discussions of the various 
activities that public utility providers should be required to 
undertake in order to show power production forecasting is in use. 
Public Interest Organizations suggest that the Commission require 
public utility transmission providers to demonstrate that VER power 
production forecasts are incorporated into unit commitment, scheduling, 
and dispatch efforts. Oregon & New Mexico PUC state that at a minimum, 
a public utility transmission provider needs to demonstrate that it has 
requested meteorological and operational data from wind and solar 
generators and has integrated forecast information into control room 
operations.
    300. Some commenters contend that the public utility transmission 
provider should demonstrate that it is using the VER forecast to 
efficiently and reliably commit and dispatch resources. These parties 
offer various criteria regarding costs, accepted industry practices, 
and performance metrics that should be required of public utility 
transmission providers in order to be deemed compliant with the Final 
Rule.\313\ The California PUC states that, while it does not recommend 
that the Commission set specific minimum quality standards or cost 
maximums for VERs forecasts at this time, the Commission should monitor 
results of public utility transmission providers' assessments. If the 
quality of forecasts varies significantly among public utility 
transmission providers, the Commission may determine that minimum 
quality standards or maximum cost limits for VERs forecasts are 
necessary to prevent unjust, unreasonable, or unduly discriminatory 
rates.
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    \313\ E.g., AWEA; California PUC; Iberdrola; NaturEner.
---------------------------------------------------------------------------

    301. Other commenters argue that the Commission should ensure that 
the risks associated with inaccurate schedules or resource specific 
forecasts remain with the VER.\314\ Montana PSC states that the 
forecasting requirement should be the responsibility of VER instead of 
the public utility transmission provider. NorthWestern states that it 
is inappropriate to make

[[Page 41530]]

the public utility transmission provider responsible for forecasting 
the VER power output when it is the responsibility of the VER to 
provide its schedule. NorthWestern points out that, if the public 
utility transmission provider provides a forecast of the VER power 
production, as proposed by the Proposed Rule, and the VER submits a 
different schedule, Control Performance Standard 2 violations may occur 
that would not have occurred if an accurate power production forecast 
had been submitted by the VER. NorthWestern argues that the forecasting 
requirement would place the balancing authority in an unacceptable 
position if the forecast or power production data is inaccurate. 
Midwest ISO Transmission Owners state that regardless of whether the 
public utility transmission provider requires VERs to provide 
meteorological data or employs other tools in order to increase the 
effectiveness of scheduling and dispatching activities, all generation 
resources must retain the ultimate responsibility for determining their 
unit's deliverability; accordingly, variations from scheduled 
deliveries must remain the responsibility of the generating resource, 
including VERs.
---------------------------------------------------------------------------

    \314\ E.g., AEP; Large Public Power Council; Midwest ISO 
Transmission Owners; Montana PSC; NorthWestern.
---------------------------------------------------------------------------

    302. Bonneville Power argues that, if the Commission requires 
centralized power production forecasts for public utility transmission 
providers with significant amounts of VERs on their systems that intend 
to differentiate their Schedule 10 pricing, it is preferable that the 
Commission also require all VERs to schedule according to the 
centralized forecast component for each plant. Puget explains that, if 
the public utility transmission provider's forecast sets the schedule, 
then there could be a perverse incentive for public utility 
transmission providers to generate inaccurate forecasts and collect 
larger generator imbalance charges under Schedule 9; however, if the 
VER is permitted to set its own schedule that differs from the public 
utility transmission provider's forecast, it remains unclear how the 
public utility transmission provider is supposed to manage and deploy 
its resources--according to its own forecast or to the VER's schedule. 
Puget requests that these questions be clarified before the Commission 
implements a power production forecasting requirement for public 
utility transmission providers, whether as a stand-alone mandate or as 
a precondition to Schedule 10 cost recovery.
    303. Invenergy argues that the Final Rule should hold public 
utility transmission providers: (1) Accountable for the accuracy of the 
forecasts that they use to determine regulation capacity requirements; 
and (2) to performance levels that current technology supports. 
Invenergy states that ISOs and RTOs that have implemented centralized 
wind forecasting are generally realizing accuracy rates of 89 percent 
or greater. Invenergy argues that the Final Rule should require the 
public utility transmission provider to provide customers with 
forecasting performance metrics on a periodic basis and, if forecasts 
do not prove to be reliable, require the public utility transmission 
provider to take immediate steps (including improving its forecasting 
systems and equipment or relinquishing responsibilities to an 
independent third party) to ensure that future forecasts are accurate.
    304. Commenters state that in RTO regions, the RTO would be the 
more appropriate entity to conduct power production forecasting. 
National Grid asks the Commission to clarify who the ``transmission 
providers'' are that will undertake the energy forecasting 
responsibility. National Grid states that the role of developing and 
implementing energy forecasting tools is well suited to a centralized 
entity with existing capabilities in data collection, region wide 
system forecasting and centralized dispatch responsibilities such as 
RTOs and ISOs. National Grid requests that the Commission clarify that 
for the purposes of its data forecasting Final Rule the term 
``transmission provider'' means the ISOs or RTOs in those regions, as 
this avoids confusion where the term ``transmission provider'' can 
refer to either the ISO or its members.
    305. Some commenters point out that many regions are currently 
undertaking their own forecasting and data gathering initiatives or 
programs to integrate VERs, and request that the Commission allow for 
regional flexibility.\315\ Pacific Gas & Electric requests that 
individual public utility transmission providers be given flexibility 
on how to implement that requirement. Pacific Gas & Electric requests 
that in its Final Rule the Commission provide latitude for the 
California ISO and other similarly situated transmission providers to 
continue their existing programs to gather the relevant meteorological 
and operational data, and to propose incremental refinements to them, 
so long as the programs maintained by these transmission providers can 
accomplish the purposes set forth in the Proposed Rule for gathering 
this information.
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    \315\ E.g., Massachusetts DPU; Pacific Gas & Electric; Midwest 
ISO.
---------------------------------------------------------------------------

iv. One Year Data Requirement
    306. Some commenters contend that the proposal to require public 
utility transmission providers to collect power production forecasting 
data for one year prior to instituting a differentiated regulation 
requirement for VERs violates cost causation principles and imposes 
costs of balancing reserve capacity needed for VERs on other 
customers.\316\ Such commenters maintain that the one-year data 
collection requirement unreasonably delays public utility transmission 
providers from demonstrating that they are entitled to recover 
different volumetric amounts associated with providing generator 
regulation service from different types of generators.\317\ Bonneville 
Power argues that there may be sound economic and operational bases for 
providing or procuring differential quantities of incremental and 
decremental balancing reserve capacity. Western Farmers suggest that 
the Commission allow public utility transmission providers to propose 
the volumetric component of the Schedule 10 charge along with the 
proposed rates in their initial Schedule 10 compliance filing. Natural 
Gas and Puget similarly argue that public utility transmission 
providers should have an opportunity to allocate ancillary service 
costs as soon as they are justifiably able to do so. MidAmerican 
contends that the one-year data collection requirement is inconsistent 
with the Westar precedent.
---------------------------------------------------------------------------

    \316\ E.g., Bonneville Power; Puget; MidAmerican; Southern 
California Edison; Natural Gas.
    \317\ E.g., EEI; MidAmerican; Puget; WUTC.
---------------------------------------------------------------------------

    307. Some commenters suggest that public utility transmission 
providers should be permitted to establish rates using historical data, 
subject to adjustment as necessary over time.\318\ For example, 
Bonneville Power states that rates can be updated as public utility 
transmission providers gain experience with reductions in the need for 
balancing reserve capacity requirements associated with intra-hourly 
scheduling, centralized forecasting and any other initiatives. 
Similarly, Puget suggests that reductions in the VERs volumetric 
component could be incorporated into a subsequent rate filing after 
implementation of 15-minute scheduling and power production forecasting 
by the utility. NorthWestern suggests that, just as the Commission 
routinely allows a proposed rate to take effect on an interim basis 
subject to refund until final approval is received, the Commission 
likewise should consider

[[Page 41531]]

applying a similar principle in allowing interim regulating service 
cost recovery. Pacific Gas & Electric proposes that until one year's 
worth of data are available, public utility transmission providers 
should be able to use simulated data to estimate the relative 
contribution of load, imports, VERs and other generation for the 
overall need for generator regulation reserves.
---------------------------------------------------------------------------

    \318\ E.g., Bonneville Power; Southern California Edison; 
California PUC; EEI; NorthWestern.
---------------------------------------------------------------------------

    308. In contrast, Vestas argues that public utility transmission 
providers should be required to implement the two operational changes 
immediately and then collect data over at least the next 12 months 
regarding the levels of schedule deviations on their systems for all 
types of generation. According to Vestas, the Commission should require 
the submission of that data to the Commission and take comments from 
interested market participants on the appropriate rate mechanism to 
permit the recovery of any costs incurred to address remaining 
variations between generator schedules and generator output.
    309. Organization of Midwest ISO States asks the Commission to 
require public utility transmission providers with significant VER 
capacity, such as three percent or more of total capacity, to submit 
statistical data on the variability of generation across the different 
types of generation resources and load. If there is a significant 
difference between types of resources, Organization of Midwest ISO 
States contends that the public utility transmission provider should be 
required to allocate the costs of increased regulation and other 
ancillary services developed in the future to the generation resources 
causing those costs.
v. Other
    310. Some commenters express concern about the static nature of the 
rates and volumes in Schedule 10.\319\ SEIA argues that public utility 
transmission providers who have selected a methodology and begun to 
apply different Schedule 10 rates for different categories of customers 
should be required to revisit their forecasting methodologies and rates 
on a regular basis. RenewElec notes that data collected over a one-year 
period that may feature anomalies (e.g., wind droughts). RenewElec 
suggests that the Commission require transmission providers to retain 
data provided under the new pro forma LGIA Article 8.4 for at least 10 
years and commit to performing annual follow-up studies over a period 
of not less than five years that update power production forecasts with 
new data received. RenewElec suggests that the Commission include a 
biannual re-opener provision for VER-specific Schedule 10 charges, or 
through other review and implementation combinations.
---------------------------------------------------------------------------

    \319\ E.g., SEIA, RenewElec, NaturEner.
---------------------------------------------------------------------------

    311. NaturEner asserts that an annual re-evaluation of the 
integration charge needs to be undertaken to take into account the 
impact of increased diversity, improved operations, market innovations 
and other changed circumstances, as well as to correct any inaccuracy 
in the original (or immediately prior) assessment. NaturEner also 
requests clarification regarding whether a VER transmission customer 
could be required to pay a VER integration charge in arrears if a 
public utility transmission provider is subsequently permitted to levy 
the charge.
    312. Some commenters oppose the Commission's proposal to group 
resources together for the purpose of allocating Schedule 10 
volumes.\320\ For example, BrightSource states that assigning all VERs 
the same regulation requirement could distort the incentives created by 
the cost allocation if they are evaluated as a single, undifferentiated 
class. First Wind asserts that the rate should be designed to recognize 
the actual variability of output of the resource paying the rate 
because two wind generation projects of the same installed capacity and 
energy production might have different levels of variability due to 
factors such as local differences in the variability of the ``wind 
resource'' (the relative wind generating value of the location); the 
number, size, and manufacturer of the wind turbines; and differences in 
distances between wind turbines. RenewElec offers that high capacity 
wind generation units have a disproportionally smaller impact on 
variability than lower capacity units. According to AWEA, the 
variability of resources within a category cancels each other out to 
the benefit of those resources in that category, imposing a 
disadvantage on customers that are grouped in smaller categories.
---------------------------------------------------------------------------

    \320\ E.g., BrightSource; FirstWind; RenewElec; AWEA.
---------------------------------------------------------------------------

    313. Snohomish County PUD questions whether it is appropriate to 
apportion any volume of generator regulation reserves to behind-the-
meter generation. Snohomish County PUD contends that variations in 
output from the behind-the-meter generator are, from the perspective of 
the public utility transmission provider, indistinguishable from 
variations in the distribution utility's load. Accordingly, Snohomish 
County PUD asks the Commission to clarify that behind-the-meter 
generators--those that are interconnected directly to and consumed by 
the load of the local distribution utility rather than a transmission 
utility--will not be required to purchase generator balancing capacity 
from the public utility transmission provider in the absence of a 
voluntary agreement between the public utility transmission provider 
and the generator to install appropriate metering that measures the 
variability of the generator and to pay the Schedule 10 charges 
justified by that variation.
    314. Several commenters suggest that the Commission convene a 
technical conference or require other processes to determine the 
appropriate per-unit and volumetric rates under the proposed Schedule 
10.\321\ AWEA states that a technical conference would be appropriate 
to establish consistent principles for determining the methodology that 
should be used for calculating and allocating Schedule 10 costs. Some 
commenters request that the Commission require stakeholder involvement 
in connection with the development of Schedule 10 volumes.\322\ For 
example, First Wind requests that the Commission require RTOs to 
conduct a robust and transparent stakeholder process which attempts to 
reach consensus prior to them making an allocation filing, and that 
non-RTO public utility transmission providers conduct public workshops 
prior to any allocation filing.
---------------------------------------------------------------------------

    \321\ E.g., AWEA; BrightSource; EPSA; SEIA.
    \322\ E.g., California PUC; First Wind; SEIA.
---------------------------------------------------------------------------

b. Commission Determination
    315. For the reasons discussed above, the Commission is not 
implementing a generic Schedule 10 to the pro forma OATT for generator 
regulation service. Instead, the Commission takes this opportunity to 
respond to the individual commenter concerns regarding the proper 
design of a generator regulation service charge in order to provide 
guidance in the development of proposals for such services.
    316. In response to the Large Public Power Council and Puget, those 
public utility transmission providers that choose to propose a rate 
schedule for generator regulation service may include opportunity costs 
for generator regulation service in certain circumstances. Such 
resources are often dispatched in the middle of their operating range 
to allow the generator to provide regulation-up as well as

[[Page 41532]]

regulation-down and as a result forego other opportunities. Not to 
allow compensation would create a barrier to the provision of services 
by frustrating the recovery of legitimate costs.
    317. A number of commenters question the appropriate design of the 
volumetric component of Schedule 10 rates, i.e., the component in the 
Proposed Rule that allowed public utility transmission providers to 
require different transmission customers (or generator classes) to 
purchase or otherwise account for different quantities of regulation 
reserves based on cost causation principles. The Commission agrees that 
calculating the relative impact of individual customers or customer 
classes on a public utility transmission provider's overall generation 
regulating reserve needs and allocating those costs accordingly can be 
a difficult and complex determination. However, the Commission believes 
that the complexity of these proceedings can be mitigated where 
entities take note of, and incorporate, the following principles.
    318. First, public utility transmission providers seeking to 
distinguish customers into classes for the purpose of requiring them to 
purchase or otherwise account for different quantities of generation 
regulating reserves should do so only to the extent such classes and 
distinctions among classes are reasonably related to operational 
similarities and differences among those resources.\323\
---------------------------------------------------------------------------

    \323\ See Westar, 137 FERC ] 61,142 at PP 27-28.
---------------------------------------------------------------------------

    319. Second, to the extent a public utility transmission provider 
proposes to break customers into specific groups based on operational 
characteristics, we expect public utility transmission providers to 
provide detailed explanations as to why such classifications are 
appropriate if and when they propose to allocate different generating 
regulation reserve obligations to different customer classes. The 
Commission has required that overall generator regulation requirements 
be established by taking diversity benefits into account. Diversity 
benefits result from aggregating the variations of all resources so 
that one resource's negative deviation can offset some or all of 
another resource's positive deviation. When the transactions of two 
customers result in diversity benefits, it is incorrect to say that one 
customer is benefitting the other but not vice versa. Instead, the 
diversity benefits result from both transactions and sharing of these 
benefits among the customers is reasonable. In Westar, the Commission 
found that this portfolio-wide approach to assessing generator 
regulation charges appropriately shares diversity benefits among 
generators and load.\324\ Ultimately, this concept will need to be 
reconciled with any customer classifications proposed by the public 
utility transmission provider in a way that prevents any over-recovery 
of these capacity costs.
---------------------------------------------------------------------------

    \324\ See Westar, 130 FERC ] 61,215 at PP 37-38.
---------------------------------------------------------------------------

    320. Third, to the extent a public utility transmission provider 
proposes to differentiate among customers (or customer classes) in 
determining their relative regulating reserve responsibilities, the 
public utility transmission provider must demonstrate that the overall 
quantity of regulating reserve it requires of its transmission 
customers accounts for diversity benefits among all resources and 
loads, and the allocations to individual customers (or customer 
classes) of their proportionate share is based on the operational 
characteristics of such customers (or customer classes).
    321. Fourth, weather events such as droughts may affect the 
required quantity of generator regulating reserves that the public 
utility transmission provider must have in reserve more or less during 
one portion of the year versus another portion of the year. In such 
cases, these diversity events, though perhaps characterized as 
anomalies, should be included in the data set so that the quantity and 
costs of such reserves are more reflective of actual system operations.
    322. Fifth, there is a relationship between the use of intra-hour 
scheduling by transmission customers and the quantity of reserves 
needed to provide Schedule 9 generator imbalance service. In other 
sections of this Final Rule, the Commission requires all public utility 
transmission providers to offer transmission customers the option of 
using more frequent transmission scheduling intervals within each 
operating hour, at 15-minute intervals, noting that over time public 
utility transmission providers will be able to rely more on planned 
scheduling and dispatch procedures and less on reserves to maintain 
overall system balance. In the Proposed Rule, the Commission sought 
comment on whether to condition the ability of public utility 
transmission providers to require different transmission customers to 
purchase or otherwise account for different quantities of generator 
regulating reserves on the implementation of intra-hour scheduling 
reforms. Given that such reforms are mandated in this Final Rule, the 
Commission concludes that condition to be satisfied.\325\ In designing 
any proposals for generator regulation service charges, a public 
utility transmission provider should consider the extent to which 
transmission customers are using intra-hour scheduling in evaluating 
whether to require different transmission customers to purchase or 
otherwise account for different quantities of generator regulating 
reserves.
---------------------------------------------------------------------------

    \325\ See supra IV.A.1 (Intra-Hour Scheduling Requirement).
---------------------------------------------------------------------------

    323. Sixth, there also is a relationship between the use of power 
production forecasting and the allocation of generator regulation 
reserve quantities to a particular class of customers. The record in 
this proceeding demonstrates that the quantity of reserves used to 
provide generator regulation service can be most efficiently managed 
with the implementation of power production forecasting (as well as 
intra-hour scheduling) by public utility transmission providers. While 
commenters disagree on the extent to which power production forecasting 
may affect reserve commitments, the Commission finds that 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 services, such 
as regulation reserve. Without the increased situational awareness of 
projected variability provided by power production forecasts, the 
public utility transmission provider's ability to commit or de-commit 
resources providing regulation reserves efficiently can be constrained. 
This lack of situational awareness potentially can result in rates for 
generator regulation service that are unjust and unreasonable or unduly 
discriminatory.
    324. We recognize that conditioning the allocation of different 
quantities of regulation reserves to different transmission customers 
on the public utility transmission provider developing and deploying 
power production forecasting is contentious. On one hand certain public 
utility transmission providers believe that they should either be able 
to use historical data or make other approximations to establish the 
quantity of regulation reserves to be required of a given transmission 
customer or class of customers. On the other hand, transmission 
customers that are VERs contend that the Commission has not gone far 
enough and that additional reforms are necessary to

[[Page 41533]]

ensure that VERs do not disproportionately bear the burden of the cost 
of regulating reserves. The Commission believes that public utility 
transmission providers need an effective opportunity to file for cost 
recovery, while VERs need assurance that they are not unduly assigned 
costs.
    325. Accordingly, while the Commission reserves judgment as to the 
appropriate power production forecasting requirements for a particular 
public utility transmission provider, we expect that the implementation 
of power production forecasting will be addressed in any proposal to 
require different transmission customers to purchase or otherwise 
account for different quantities of generator regulating reserves. For 
example, a public utility transmission provider could demonstrate that 
it is utilizing power production forecasts (or other comparable 
technique) to manage system operating costs and/or to improve 
reliability by enabling the more efficient commitment and dispatch of 
resources. The Commission agrees with the California PUC that, as part 
of such a demonstration, the public utility transmission provider 
should explain how the data required from VERs are incorporated into 
the power production forecast and how the resulting forecast is used to 
support the management of operating costs and/or reserves or otherwise 
ensure that capacity costs incurred to provide Schedule 9 service are 
prudently incurred.
    326. The Commission declines to require the additional forecasting-
related showings suggested by NaturEner and others. The technologies 
and techniques for power production forecasting are still being refined 
and may differ from region to region. While the recommendations made by 
AWEA, Iberdrola, and NaturEner may be appropriate benchmarks for power 
production forecasts utilizing today's technology, the Commission 
believes that pre-defining these additional criteria would not provide 
the flexibility needed for public utility transmission providers to 
adopt new forecasting techniques or technologies as they are developed. 
The Commission also declines to adopt the further recommendations of 
the California PUC and others to include monitoring and reporting 
requirements for public utility transmission providers that engage in 
power production forecasting. The Commission finds adopting these 
requirements to be unnecessary at this time.
    327. However, the Commission agrees with Iberdrola and others that 
the public utility transmission provider should make the results of any 
centralized forecast used by the public utility transmission provider 
available through a secure information exchange to VER generators 
providing related data. The Commission believes that the VERs should be 
able to access the results of the public utility transmission 
provider's forecast in order to ensure that the forecasting service is 
producing accurate results. Thus, public utility transmission providers 
proposing to require different transmission customers to purchase or 
otherwise account for different quantities of generator regulating 
reserves should explain in their proposals how forecasting results will 
be shared.
    328. In response to comments regarding forecasting risk, the 
Commission clarifies that the transmission customer is responsible for 
the accuracy of transmission schedules and the public utility 
transmission provider is responsible for the reliability of its system. 
Therefore, the public utility transmission provider would utilize the 
power production forecast to identify the necessary amount of reserves 
and to use those reserves to maintain reliability of the transmission 
system. The obligation of the transmission customer is to submit 
schedules for deliveries. Power production forecasting is intended to 
inform the transmission provider regarding aggregate system variability 
that results from having VERs on its system, not to replace 
transmission schedules from transmission customers delivering from 
VERs. Public utility transmission providers using power production 
forecasts should do so to manage uncertainty in the same manner they 
use other forecasts of uncertainty for the transmission system. For 
example, despite service agreements to serve load, public utility 
transmission providers develop and use load forecasts to assure load 
can be met reliably and efficiently. Similarly, despite transmission 
schedules to deliver from a VER, public utility transmission providers 
should use power production forecasts to assure energy can be provided 
to load in a reliable and efficient manner.
    329. Therefore, the Commission agrees with NorthWestern and others 
that the transmission customer maintains responsibility for the 
accuracy of its transmission schedule. However, we disagree with 
NorthWestern's interpretation concerning NERC Control Performance 
Standard 2 violations. A public utility transmission provider is not 
responsible for submitting a transmission schedule on behalf of a VER. 
As explained above, power production forecasting would be utilized to 
identify and acquire the appropriate amount of reserves needed to 
integrate VERs reliably. Nothing in this Final Rule alleviates the 
public utility transmission provider's obligations under NERC 
Reliability Standards.
    330. The Commission declines to require transmission customers 
delivering from a VER to submit transmission schedules according to the 
public utility transmission provider's forecast, as suggested by 
Bonneville Power. While the public utility transmission provider is 
able to forecast the aggregate variability of the system with greater 
accuracy through centralized power production forecasting, the 
individual VER may be better able to produce the most accurate schedule 
for its particular facility. Requiring a transmission customer to 
submit transmission schedules for VER deliveries according to a 
centralized forecast would cloud the delineation between the 
obligations of the VER and the obligations of the public utility 
transmission provider with respect to the provision of transmission 
service.
    331. The Commission disagrees with Puget's example, and clarifies 
that the public utility transmission provider's obligation should be to 
deploy its resources according to its own forecast in order to maintain 
the reliability of the system. The public utility transmission provider 
retains the risk and responsibility for inaccurate procurement of 
reserve requirements while the transmission customer retains the 
financial risk and responsibility for inaccurate schedules. The 
Commission finds that the incentive to avoid Schedule 9 generator 
imbalance penalties and any relevant charges for generator regulation 
service provides sufficient incentive for VERs to submit an accurate 
schedule.
    332. The Commission agrees with National Grid and others that, as 
the entity providing transmission service under an OATT, the ISO or RTO 
would engage in power production forecasting within its region. In 
response to Pacific Gas & Electric and others requesting flexibility to 
implement power production forecasting, the Commission finds that the 
guidance provided affords sufficient flexibility to allow public 
utility transmission providers to tailor their forecasting programs to 
meet their needs, whether for the purpose of developing proposals for 
generator regulation charges or otherwise.
    333. The Commission emphasizes that the foregoing discussion is 
intended to provide a framework to assist public utility transmission 
providers in

[[Page 41534]]

developing proposals for generator regulation service should they 
desire to do so. The Commission does not intend this guidance to 
preclude a public utility transmission provider from making an 
alternative proposal under section 205 of the FPA. However, it does 
provide guidance to public utility transmission providers regarding the 
facts and circumstances that the Commission may find relevant in 
evaluating such proposals.
    334. A number of commenters challenged the Commission's proposal to 
condition proposals that require different transmission customers to 
purchase or otherwise account for different quantities of generator 
regulating reserves on performance of the activities discussed above. 
These arguments have largely been rendered moot by the Commission's 
decision not to adopt the Proposed Rule in that regard. Even as applied 
to the guidance provided above, the Commission disagrees that a future 
decision by the Commission to condition proposals that require 
different transmission customers to purchase or otherwise account for 
different quantities of generator regulating reserves on the 
performance of certain actions would violate cost causation principles 
or otherwise would preclude public utility transmission providers from 
recovering prudently incurred costs. In reviewing any future proposal 
to allocate a greater quantity of capacity costs to a particular set of 
transmission customers, it would be reasonable for the Commission to 
consider whether the public utility transmission provider has taken 
steps to mitigate such costs. This does not mean, as some commenters 
imply, that the public utility transmission provider has no other means 
to recover its costs. The public utility transmission provider could 
continue to rely on existing rate mechanisms to recover reserve costs 
or may propose to require a uniform quantity of generation regulating 
reserves from all transmission customers that is commensurate with 
transmission customers' proportionate effect on net system variability 
and taking diversity benefits into account.
    335. The Commission agrees with commenters that implementing other 
reforms, such as consolidating balancing authority areas or 
implementing an ancillary services market, may be beneficial to the 
reliable and efficient integration of VERs. However, the Commission is 
not persuaded that these additional reforms are a necessary 
precondition to proposals that require different transmission customers 
to purchase or otherwise account for different quantities of generator 
regulating reserves. As noted in the Proposed Rule, many of these 
additional reforms are being discussed in other forums. The Commission 
will continue to monitor these proposals as they develop and modify our 
approach to this issue as appropriate as conditions develop.
3. Use of Contingency Reserves
a. Commission Proposal
    336. In the Proposed Rule, the Commission sought comments from NERC 
and industry stakeholders on the steps needed to resolve confusion 
regarding the use of contingency reserves to manage extreme ramp events 
of VERs.\326\ The Commission also sought comments from NERC and 
industry stakeholders on the extent to which some additional type of 
contingency reserve service (beyond the services provided under 
Schedule 5 and 6 of the pro forma OATT) would ensure that VERs are 
integrated into the interstate transmission system in a non-
discriminatory manner while remaining consistent with NERC Reliability 
Standards.\327\
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    \326\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 100 
(citing Schedule 5 (Operating Reserve--Spinning Reserve Service) and 
Schedule 6 (Operating Reserve--Supplemental Reserve Service) respond 
to contingency events. Spinning Reserve Service is used to serve 
load ``immediately in the event of a system contingency'' whereas 
Supplemental Reserve Service ``is not available immediately to serve 
load but rather within a short period of time.'').
    \327\ Id. P 100.
---------------------------------------------------------------------------

b. Comments
    337. NERC indicates that large wind ramping events are similar to 
conventional generator contingency events in that they are large and 
relatively infrequent, yet they differ in that wind ramps are much 
slower than instantaneous contingency events and may be possible to 
forecast. NERC states that the use of contingency reserves to address 
wind ramps is similar to what is used to address large, relatively 
infrequent wind ramps because contingency reserves are seldom deployed, 
yet long ramp durations can make it difficult to include wind ramps as 
actual contingencies. NERC explains that Resource and Demand Balancing 
(BAL) Reliability Standard BAL-002 (Disturbance Control Performance) 
requires ACE to be restored 15 minutes following the disturbance (R4) 
and the contingency reserves to be restored within 105 minutes (90 
minutes after the 15 minute disturbance recovery period--R6). NERC 
states that both of these requirements can be problematic for wind 
ramps because they can be longer than the disturbance recovery period 
as well as the reserve restoration period.
    338. Still, NERC indicates that it may be appropriate to use 
contingency reserves in response to a portion of a wind ramp. NERC 
states that shared contingency reserves could be used to initiate the 
response, allowing time for alternate supply (or load reduction) to be 
implemented. NERC suggests that the industry consider developing rules 
governing reserve deployment and restoration, similar to those that 
currently address conventional contingencies.
    339. Other commenters express openness to using contingency 
reserves for wind events.\328\ Commenters indicate that there are 
discussions in the Northwest Power Pool (NWPP) about the use of 
contingency reserves for wind events.\329\ AWEA contends that 
contingency reserves should be used for the initial period of an 
extreme wind ramp because both contingency events and extreme wind ramp 
events are very infrequent, and therefore, the use of contingency 
reserves for extreme wind ramp events would be highly unlikely to 
coincide with a need to use those reserves for a conventional 
generator's contingency event. NextEra urges the Commission to convene 
a technical conference to address how to deploy contingency reserves to 
address ramp events in a manner that will promote reliability.
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    \328\ E.g., Powerex; NaturEner; California PUC; MidAmerican.
    \329\ E.g., Powerex; Tacoma Power.
---------------------------------------------------------------------------

    340. Xcel indicates that there is confusion regarding the use of 
contingency reserves to manage extreme ramping events. Xcel states that 
the confusion arises as entities attempt to define the allowable 
triggering events for the activation of contingency reserves. Xcel 
recommends that the standard for contingency reserve activation include 
disturbances related to less-than-anticipated VER (e.g., wind) 
production, sudden drop-off of VER production, or associated ramp 
limitations on balancing resources due to forecast errors. Xcel 
contends that ramp events related to VERs are not necessarily caused by 
the sudden failure of generation, but instead may be due to an 
incorrect wind forecast or limited dispatchable generation response. 
For these reasons, Xcel recommends: (1) Expanding the definition of 
disturbances to include ramp events which may occur over a half-hour 
time frame; (2) including a measurement technique related to a ramp 
event in BAL-002; (3) identifying a specific

[[Page 41535]]

restoration period in BAL-002 (e.g., 45 minutes) related to contingency 
reserves that were deployed for ramping events; and (4) identifying 
compliance metrics and other issues related to deployment of 
contingency reserves for ramp-limited events. Xcel recommends that the 
Commission request that NERC begin a standards drafting process to 
consider revisions to the existing BAL-002 standard to address the 
issues discussed by Xcel.
    341. Other commenters express reservations with using contingency 
reserves in response to wind events is an improper use of contingency 
reserves.\330\ Duke indicates to the extent that there is a need for a 
new service to address VER ramp rates, a new rate schedule should be 
developed for such a service. Pacific Gas & Electric states that there 
may be a need for new integration services to incorporate VERs into the 
reliable operation of the grid. Pacific Gas & Electric submits that 
various industry activities are already underway to consider these 
issues, and the Final Rule should endorse their continued efforts.
---------------------------------------------------------------------------

    \330\ E.g., Tacoma Power; ENBALA; Grant PUD; California ISO; 
Duke; Pacific Gas & Electric.
---------------------------------------------------------------------------

c. Commission Determination
    342. Based on comments received, the Commission concludes that the 
issues related to the appropriate use of contingency reserves under 
NERC Reliability Standards need further study and vetting before any 
action is considered. Indeed, comments range from expressing confusion 
over what would constitute an extreme VER event to asking the 
Commission to define ``ramp'' with some specificity. Rather than 
opining on any of the comments and risk providing guidance without the 
benefit of more information, the Commission finds that the better 
course of action is to allow industry to continue its work and direct 
our staff to monitor those efforts and engage industry as appropriate.

V. Other Issues

1. Regulatory Text
a. Commission Proposal
    343. As part of the Proposed Rule, the Commission sought comment on 
a minor revision to 18 CFR 35.28. To date, when amending its 
regulations concerning the open access requirements of the pro forma 
OATT, the Commission has listed by name Commission rulemaking 
proceedings promulgating and amending the pro forma OATT when 
explaining the details of a public utility transmission provider's 
obligation to have an OATT on file with the Commission. The Commission 
proposed to no longer explicitly reference, by name, prior Commission 
rulemaking proceedings promulgating and amending the pro forma OATT in 
its regulations. Likewise, the Proposed Rule included a similar change 
with respect to a public utility transmission provider's obligation to 
have standard generator interconnection procedures and agreements and 
standard small generator interconnection procedures and agreements on 
file with the Commission.\331\
---------------------------------------------------------------------------

    \331\ Proposed Rule, FERC Stats. & Regs. ] 32,664 at P 12 & 
n.29.
---------------------------------------------------------------------------

b. Comments
    344. No comments were received on this aspect of the Proposed Rule.
c. Commission Determination
    345. The Commission adopts its proposed minor revision to 18 CFR 
35.28. We find that the existing process for amending regulations 
concerning the pro forma OATT, which necessitates listing by name 
Commission rulemaking proceedings promulgating and amending the pro 
forma OATT when explaining the details of a public utility transmission 
provider's obligation to have an OATT on file with the Commission, is 
increasingly cumbersome and provides little, if any, benefit. Thus, the 
Commission will no longer explicitly reference, by name, prior 
Commission rulemaking proceedings promulgating and amending the pro 
forma OATT in its regulations. Likewise, the Final Rule adopts a 
similar change with respect to a public utility transmission provider's 
obligation to have standard generator interconnection procedures and 
agreements and standard small generator interconnection procedures and 
agreements on file with the Commission.
2. Market Mechanisms
a. Comments
    346. Several commenters ask the Commission to revise specific RTO 
and ISO market rules not at issue in the Proposed Rule, while other 
commenters seek to have the Commission address additional market 
mechanisms for the non-RTO and ISO areas. For example, Environmental 
Defense Fund states that the Proposed Rule does not reform the day-
ahead market to increase VER participation and decrease the amount of 
costly out-of-market commitments, leading to unjust and unreasonable 
rates, and undue discrimination against VERs. In addition, ACSF asserts 
that scheduling in the day-ahead market and in the unit commitment 
process should be reformed. ACSF states that the technology that makes 
15-minute schedules feasible in the spot market also makes reforms 
possible in these other areas. According to ACSF, it is important to 
prevent the least clean and efficient generation from dominating 
dispatch at all hours, especially in the unit commitment process.
    347. Environmental Defense Fund further states that because VERs 
are only permitted to bid a portion of their capacity into the market, 
they generally receive a lower price. According to Environmental 
Defense Fund, many capacity markets require bidders to also participate 
in the day-ahead market, which most VERs do not do because of the 
financial risk associated with failing to meet day-ahead obligations. 
Thus, Environmental Defense Fund argues that the Commission must 
consider the available options to facilitate VER participation in 
capacity markets.
    348. With regard to non-RTO regions, EPSA states that the Proposed 
Rule does not sufficiently address the lack of market mechanisms 
available in non-RTO regions to conventional generation resources, 
which have the ability to contribute to VERs integration. EPSA suggests 
that possible market mechanisms and other competitive options for 
integrating VERs in the non-RTO regions should be considered as part of 
the technical conference that EPSA has requested. Similarly, 
Independent Power Producers Coalition--West states that without an 
organized ISO or RTO market, public utilities must face regulatory 
pressure to advance their integration of VERs and sharing of data, 
otherwise the utilities have little incentive to move toward better 
integration between transmission providers and balancing authorities. 
Independent Power Producers Coalition--West contends that the lack of a 
competitive ancillary services market that would allow independent 
power producers the opportunity to provide generator imbalance services 
in WECC results in unjust and unreasonable rates.
    349. Tres Amigas contends that Order Nos. 888 and 890 have left 
little room for a market to develop balancing services outside of an 
ISO/RTO, because the primary provider of these services, the balancing 
authority, has to acquire the capability to provide the ancillary 
services on behalf of all its transmission customers and then sell the 
services at cost-based rates. Tres Amigas states that the Commission 
should have a two-fold objective: (1) Determining how market

[[Page 41536]]

forces can identify and competitively price the resources that will be 
used by balancing authorities for balancing; and (2) establishing 
appropriate mechanisms for allocating the costs incurred by balancing 
authorities to acquire these resources in the marketplace. Further, 
Tres Amigas asserts that the Commission should grant market-based rates 
to new entrants in order to promote formation of a vibrant market for 
balancing services that includes participation by new technologies. 
Tres Amigas states that the balancing authorities should then file 
proposals to allocate the costs incurred to balance the system among 
load and generation (including generation within the control area that 
is scheduled to another control area). According to Tres Amigas, these 
cost allocation proposals should take into account the extent to which 
different market participants contribute to the costs of acquiring 
balancing services and benefit from such services.
    350. Recycled Energy urges the Commission to consider implementing 
various payments designed to compensate efficient gas generators and 
combined heat and power facilities for the flexibility they provide to 
utilities. In addition, Recycled Energy asserts that the Commission 
could improve the grid's reliability and efficiency by encouraging the 
placement of distributed generators in ways that reduce line losses and 
obtain ancillary benefits. Similarly, Business Council asserts that the 
OATT should be revised to ensure that flexible resources (such as 
natural gas and pumped storage facilities) are better able to provide 
their services to system operators who integrate VERs, and that these 
services are properly valued. Business Council explains that flexible 
generation resources should be given more opportunities to sell their 
balancing services to transmission providers and should be paid a just 
and reasonable rate for these services. Business Council argues that if 
the Commission adopts a universal requirement for 15-minute scheduling, 
it should make clear that generators should be able to supply balancing 
services on the same 15-minute (or less) basis.
b. Commission Determination
    351. The pro forma OATT terms and conditions of service create the 
platform by which the public utility transmission provider makes 
available non-discriminatory open, access transmission service. Since 
the issuance of Order No. 888, the Commission has taken numerous 
actions to ensure that the principles enunciated in that rule continue 
to remain true, allowing all types of resources--existing and new--
access to the grid for the benefit of developing competitive markets. 
In response to commenters like Independent Power Producers-West, EPSA 
and Tres Amigas who assert that the Commission should take various 
steps to establish a competitive ancillary services market or other 
market mechanisms, we believe that the reforms in this Final Rule 
continue to facilitate the development of competitive markets without 
imposing any particular type of structure for doing so. The Commission 
allows third party sellers to make sales of ancillary services at 
market-based rates, requires all public utility transmission providers 
to offer open access transmission service and undertake open and 
transparent transmission planning, and allows transmission customers to 
self-supply their own ancillary services. The Commission has long-
standing precedent on cost allocation and has long supported reserve 
sharing and power pooling arrangements. Nothing in this rule is 
intended to prevent or create a barrier to the further development of 
competitive markets. Indeed, we think that the reforms adopted herein 
should help to facilitate the further development of competitive 
markets by allowing transmission customers to tailor their transmission 
schedules and, in turn, better manage generator imbalance and ancillary 
services costs. As the liquidity of intra-hour energy products 
stabilizes, market participants also may begin to commit or otherwise 
acquire fewer reserves in advance, with the knowledge that they can 
purchase additional reserves on an as-needed basis from third parties. 
Requiring public utility transmission providers to offer intra-hour 
scheduling is a necessary predicate to facilitate these market 
opportunities.
    352. For similar reasons we decline the request from Recycled 
Energy and Business Council to expand the scope of this rulemaking 
proceeding to include additional payments to flexible generation. Both 
commenters urge the Commission to adopt mechanisms that would increase 
payments to flexible generation resources, such as high-efficiency 
natural gas facilities, so as to properly value the flexibility they 
provide to transmission providers. The Commission has already 
addressed, in the context of the organized markets, compensation for 
resources providing frequency regulation and is currently exploring a 
similar issue in bilateral markets outside of RTOs and ISOs.\332\ In 
this proceeding, the Commission is primarily concerned with providing 
reforms that will provide public utility transmission providers with 
greater awareness of the variability experienced on their systems, as 
well as providing transmission customers with a tool to manage 
imbalances from schedules by providing for 15-minute adjustments to 
schedules. How these public utility transmission providers choose to 
provide this service is beyond the scope of this inquiry.
---------------------------------------------------------------------------

    \332\ See Frequency Regulation Compensation in the Organized 
Wholesale Power Markets, Order No. 755, 76 FR 67260 (Oct. 31, 2011), 
FERC Stats. & Regs. ] 31,324 (2011); Third-Party Provision of 
Ancillary Services; Accounting and Financial Reporting for New 
Electric Storage Technologies, 139 FERC ] 61,245 (NOPR).
---------------------------------------------------------------------------

    353. With regard to commenters that request additional changes to 
the RTO and ISO day-ahead and capacity markets to facilitate VER 
integration, we fail to see the direct connection between the specific 
reforms of the Commission's Proposed Rule and the reforms requested. 
Commenters did not establish that connection and failed to demonstrate 
that the Commission's proposed reforms are unjust and unreasonable 
without the additional requested reforms. Instead, these commenters 
merely asked that the Commission extend the scope of the rule. As such, 
we find that commenters' requests that we require additional reforms to 
RTO/ISO day-ahead, residual unit commitment, and capacity market rules 
are beyond the scope of this proceeding.
    354. Finally, we cannot allow sales of energy or capacity at 
unchecked rates, even by new entrants, as suggested by Tres 
Amigas.\333\ As noted above, the Commission allows for sales at market-
based rates upon a showing of lack of market power and is in the 
process of considering ways to streamline the market-based rate showing 
for certain ancillary services.\334\
---------------------------------------------------------------------------

    \333\ See Market-Based Rates For Wholesale Sales Of Electric 
Energy, Capacity And Ancillary Services By Public Utilities, Order 
No. 697, 72 FR 39904 (July 20, 2007), FERC Stats. & Regs. ] 61,295, 
at P 320 (2007).
    \334\ See Third-Party Provision of Ancillary Services; 
Accounting and Financial Reporting for New Electric Storage 
Technologies, 139 FERC ] 61,245 (NOPR).
---------------------------------------------------------------------------

c. Pipeline Transportation Nomination Procedures
i. Comments
    355. Some commenters assert that if the Commission requires 
transmission providers to allow intra-hour transmission scheduling to 
accommodate VERs, the Commission must also consider the impact of such 
requirements on the operation of natural-gas-fired electric generation

[[Page 41537]]

units, and the concomitant need to modify pipeline transportation 
service nomination procedures to calibrate gas transportation and usage 
more closely with the operation of natural gas-fired electric 
generation units to support VERs.\335\ Specifically, APPA contends that 
despite access to real-time electronic metering and flow control and 
technological advances that enable the electronic submission of gas 
nominations, the current time period used to process pipeline 
transportation service nominations and to schedule natural gas is the 
same time period (up to 4 hours) that was adopted over a decade and a 
half ago. APPA notes that this already substantial disconnect between 
the nomination and scheduling procedures used in the natural gas and 
electric power industries will only become more severe if intra-hour 
scheduling is adopted. Similarly, Joint Parties request that the 
Commission open a companion docket to examine barriers that may exist 
in the natural gas industry that inhibit the timely access to natural 
gas that is needed to ensure the seamless integration of VERs.\336\
---------------------------------------------------------------------------

    \335\ E.g., Joint Parties; TVA; Midwest Energy; APPA.
    \336\ TVA contends that the Commission should reevaluate its 
policy of not allowing a firm gas transportation holder to take 
precedence over (i.e., bump) a non-firm customer, because gas-fired 
generators paying for firm gas transportation service must be able 
to support electric needs in general and in integrating VERs 
specifically.
---------------------------------------------------------------------------

    356. American Gas and INGAA state that gas transmission systems 
have developed innovative services to accommodate the needs of gas-
fired generators to access gas supplies quickly in response to electric 
system dispatch orders. American Gas and INGAA explain that these 
offerings demonstrate that individual, tailored solutions may better 
address gas-electric coordination concerns than a modification of the 
gas nomination schedule. For this reason, American Gas encourages the 
Commission to continue to be open to creative market solutions to meet 
the needs of gas-fired generators in ways that do not unnecessarily 
affect existing shippers in adverse ways. American Gas also encourages 
the Commission to hold a technical conference or other non-NAESB forum 
to discuss ways in which the natural gas and electric industries can 
work together.
    357. American Gas further contends that the Commission's 
consideration of gas-electric coordination issues should not focus 
narrowly on the gas nomination and scheduling cycle as a primary 
solution to the reliability issues which both industries face. While 
American Gas believes that a single, nationwide gas nomination schedule 
is essential to the efficient functioning of the natural gas system, a 
modification to that schedule alone is not the most effective means to 
address gas-electric coordination issues.
    358. AEP adds that while the proposed scheduling option appears on 
the surface to be feasible within the power industry, the increased 
quantity of VERs and subsequent increased ramping capability 
requirements will further exacerbate the operational difficulties 
associated with the varied scheduling timelines existing between the 
gas and power industries. AEP concludes that such discrepancies place 
the gas-fired generation operators, whose typically superior ramping 
capabilities will become increasingly beneficial, in a position of 
speculating on fuel supply needs because they are unsure whether the 
increase in variable generation will mean an increased need for the 
faster ramping capabilities of gas.
    359. AEP notes that these differences have existed for many years, 
and managing them has become more challenging with the introduction of 
RTO-administered markets, as unit commitment is generally made by the 
RTO, and not the individual asset owner. AEP argues that any proposed 
scheduling practices related to incremental VER penetration must 
account for such inter-market dependencies.
    360. Spectra Entities notes that the interface issues between the 
gas and electric industries go beyond revisiting coordinating and the 
gas/electric scheduling timelines. Spectra Entities argues that there 
are regulatory policy and market barriers discouraging the electric 
industry in some markets from contracting for adequate firm gas supply 
and firm transportation arrangements to serve those generators which 
must run in order to maintain the reliability of the electric grid. For 
example, the Commission's ``no-bump'' policy and the need to coordinate 
scheduling of interruptible services are irrelevant during peak or high 
load days in natural gas markets, because interruptible capacity is 
rarely available on the pipeline grid under those conditions. Spectra 
Entities argue that unless these barrier issues are addressed, any 
changes to coordination and scheduling or the offering of innovative 
transportation solutions will not be sufficient to achieve the 
Commission's goals.
ii. Commission Determination
    361. While comments asking the Commission to undertake reforms to 
natural gas pipeline rules and procedures in order to facilitate 
greater cross-market coordination are beyond the scope of this 
proceeding, we agree that the interdependence of these two industries 
merits careful attention. The Commission has recently addressed 
proposed changes to the gas pipeline nomination procedures. In the 
past, the Commission has urged the industry, working through NAESB, to 
consider changes to its nomination procedures to provide better 
coordination between gas and electric scheduling.\337\ More recently, 
in Order No. 587-U, the Commission acknowledged that NAESB lacked 
consensus to implement any such changes and did not find a nationwide 
scheduling solution in response to concerns over gas pipeline 
nomination procedures (including the ``no-bump'' rule).\338\ While 
eschewing nationwide changes, Order No. 587-U emphasized that 
``individual pipelines may be able to offer special services or 
increased nomination opportunities that better fit the profile of gas-
fired generation.'') \339\ In fact, some pipelines have begun to offer 
special services to facilitate the flexibility needs of gas-fired 
generation.\340\
---------------------------------------------------------------------------

    \337\ See Standards for Business Practices for Interstate 
Natural Gas Pipelines: Standards for Business Practices for Public 
Utilities, Order No. 698, FERC Stats, & Regs ] 31,251, at P 69 
(2007).
    \338\ Order No. 587-U, FERC Stats. & Regs. ] 31,307 at P 27.
    \339\  Id.
    \340\ See Texas Gas Transmission LLC, 138 FERC ] 61,176 (2012).
---------------------------------------------------------------------------

    362. On March 30, 2012, a number of entities submitted further 
comments on gas-electric coordination issues in response to a notice 
issued in Docket No. AD12-12-000 that requested comments in response to 
a set of questions and other text concerning gas-electric 
interdependence issued by Commissioner Moeller on February 3, 2012. The 
Commission is currently evaluating these comments to determine what, if 
any, additional steps would be appropriate to take to facilitate 
coordination between the gas and electric industries.
3. Power Factor Design
a. Comments
    363. Midwest ISO Transmission Owners state that Order No. 661 
exempted wind generators from having to maintain power factor design 
criteria absent a specific finding in the relevant system impact study 
that the generator needs to maintain a specific power factor in order 
to ensure safety and reliability. Midwest ISO Transmission Owners 
submit that the Commission should convene a technical conference to 
examine this issue, or allow

[[Page 41538]]

individual transmission providers to file to eliminate this exemption 
from their pro forma LGIAs or generator interconnection agreements. 
Midwest ISO Transmission Owners explain that wind and other VERs have 
obtained significant penetration levels in many areas of the country, 
such that wind is no longer a new technology that needs protection. 
Midwest ISO Transmission Owners contend that eliminating this exemption 
will ensure that wind does not receive an unfair competitive basis.
b. Commission Determination
    364. Since issuance of the Proposed Rule in this proceeding, the 
Commission has directed staff to convene a technical conference in 
Docket No. AD12-10-000 to examine whether the Commission should 
reconsider or modify the reactive power provisions of Order No. 661-A 
and examine what evidence could be developed under Order No. 661 to 
support a request to apply reactive power requirements more broadly 
than to individual wind generators during the interconnection study 
process.\341\ The Commission concludes that potential issues regarding 
the exemption provided under Order No. 661-A are better addressed in 
that proceeding.
---------------------------------------------------------------------------

    \341\ Reactive Power Resources, Notice of Technical Conference, 
Docket No. AD12-10-000 (issued Feb. 17, 2012).
---------------------------------------------------------------------------

VI. Compliance

A. Commission Proposal

    365. In the Proposed Rule, the Commission indicated that each 
public utility transmission provider must submit a compliance filing 
within six months of the effective date of the Final Rule revising its 
OATT and LGIA to demonstrate compliance with the Final Rule. The 
Commission indicated that to demonstrate compliance, a public utility 
transmission provider must file: (1) Revisions to its OATT to implement 
15-minute scheduling; (2) revisions to its LGIA to include a 
requirement for interconnection customers whose generating facility is 
a VER to provide data to the public utility transmission provider when 
the public utility transmission provider is developing and deploying 
power production forecasting for VERs; and (3) the addition of Schedule 
10 to the OATT, which includes the same per unit rate from their 
currently effective Schedule 3, and a blank or unfilled volumetric 
component, among other things.
    366. The Commission acknowledged that public utility transmission 
providers may have provisions in their existing OATTs and LGIAs that 
the Commission has deemed to be consistent with or superior to the pro 
forma OATT and LGIA. The Commission indicated that where these 
provisions are being modified by the Final Rule, public utility 
transmission providers must either comply with the Final Rule or 
demonstrate that these previously-approved variations continue to be 
consistent with or superior to the pro forma OATT and LGIA as modified 
by the Final Rule.
    367. The Commission also proposed that transmission providers that 
are not public utilities would have to adopt the requirements of the 
Final Rule as a condition of maintaining the status of their safe 
harbor tariff or otherwise satisfying the reciprocity requirement of 
Order No. 888.\342\
---------------------------------------------------------------------------

    \342\ Order No. 888, FERC Stats. & Regs. at 31,760-763.
---------------------------------------------------------------------------

B. Comments

    368. Commenters addressing the six month timeframe generally argue 
that the proposed compliance deadline does not provide enough time for 
the industry to implement intra-hour scheduling effectively.\343\ 
Specifically, commenters assert that additional time is needed to allow 
transmission providers time to: (1) Develop necessary revisions to 
inter-regional agreements and procedures, and finish ongoing pilot 
programs; and (2) evaluate all potential impacts to operations and 
address issues regarding reliability via NERC, and perhaps business 
standards via NAESB.
---------------------------------------------------------------------------

    \343\ E.g., MidAmerican; EEI; FriiPwr; NRECA; Southern 
California Edison; Pacific Gas & Electric; Grant PUD; NextEra; PNW 
Parties; Powerex; NV Energy; New York ISO; ISO/RTO Council.
---------------------------------------------------------------------------

    369. Southern California Edison argues that regional differences 
and the need to implement intra-hour scheduling efficiently require 
careful consideration of each region's scheduling rules. Specifically, 
Southern California Edison suggests that the Commission provide three 
years to implement 30-minute scheduling followed by an 18-24 month 
evaluation period before deciding if 15-minute intra-hour scheduling is 
necessary. Pacific Gas & Electric recommends that the Commission 
lengthen the implementation timeline for intra-hour scheduling, so that 
regional technical conferences on intra-hour scheduling can be convened 
for affected transmission providers, and so that ongoing pilot studies 
on intra-hour scheduling may be completed.
    370. NorthWestern comments that six months is insufficient time for 
a compliance filing implementing the intra-hour scheduling requirements 
of the Proposed Rule. NorthWestern argues that compliance will include, 
but not be limited to, implementation of software and hardware 
upgrades, adoption of common regional scheduling practices in the 
region with jurisdictional and non-jurisdictional balancing 
authorities, and hiring and properly training of additional staff. 
NorthWestern encourages the Commission to be flexible and allow 
balancing authorities the ability to define implementation timeframes, 
perhaps up to one year before the compliance filing is due.
    371. Commenters also point more generally to areas of the Proposed 
Rule that may require additional time for compliance. Midwest ISO 
Transmission Owners state, for example, that additional time may be 
needed to make changes that are highly technical or require an 
extensive stakeholder process to implement.\344\ Midwest ISO suggests 
that at least 18 months should be allotted for transmission providers 
to submit compliance filings revising their OATT, LGIA, or other 
documents.\345\ MidAmerican recommends that sufficient time be 
allocated so that transmission providers may (1) evaluate and address 
all potential impacts to operations and reliability and (2) be afforded 
the necessary time to procure resources, develop and adopt 
administrative processes, conduct training, and perform testing and 
validation critical to successfully effectuate the proposed reforms.
---------------------------------------------------------------------------

    \344\ Midwest ISO Transmission Owners at 16.
    \345\ Midwest ISO at 15.
---------------------------------------------------------------------------

    372. EEI suggests that the Commission not require the changes set 
forth in the Proposed Rule until the regional planning and cost 
allocation Final Rules have gone through any rehearing and legal 
challenges that may develop. On the other hand, Iberdrola supports the 
Commission's proposal to require a compliance filing within six months; 
however, if the Commission extends the deadline, Iberdrola recommends 
that implementation of Schedule 10 occur coincidentally with the 
implementation of the other two proposed operational changes.

C. Commission Determination

    373. The Commission extends the deadline for compliance filings by 
6 months so that public utility transmission providers will have 12 
months from the effective date of this Final Rule to submit their 
compliance filings. The Commission also provides the pro forma tariff 
language that public utility transmission providers must include in 
their OATTs and LGIAs, with modifications to the language based

[[Page 41539]]

upon the comments received, as discussed within the body of this Final 
Rule.\346\
---------------------------------------------------------------------------

    \346\ See Appendix A and B for the adopted pro forma OATT and 
LGIA provisions consistent with this Final Rule.
---------------------------------------------------------------------------

    374. Consistent with the discussion in the intra-hourly scheduling 
section, the Commission requires public utility transmission providers 
to revise their OATTs to provide an opportunity for transmission 
customers to submit transmission schedules at 15-minute intervals 
within 12 months of the effective date of this Final Rule.\347\ Public 
utility transmission providers with provisions in their existing OATTs 
that the Commission has deemed to be consistent with or superior to the 
pro forma OATT being modified by the Final Rule can seek to demonstrate 
in their compliance filings that those previously-approved variations 
continue to be consistent with or superior to the pro forma OATT as 
modified by the Final Rule. In addition, public utility transmission 
providers may submit alternative proposals that are consistent with or 
superior to the intra-hour scheduling requirements of this Final Rule 
and are otherwise just and reasonable and not unduly discriminatory or 
preferential.\348\
---------------------------------------------------------------------------

    \347\ See Appendix A for the revised section 13.8 and 14.6 of 
the pro forma OATT provisions consistent with this Final Rule. As 
noted supra Sec.  IV.A.1 (Intra-Hour Scheduling Requirement), the 
implementation of 15-minute scheduling will only apply to intertie 
transactions in organized wholesale energy markets.
    \348\ See supra Sec.  IV.A.1 (Intra-Hour Scheduling 
Requirement).
---------------------------------------------------------------------------

    375. Consistent with the discussion in the data reporting section, 
the Final Rule modifies the compliance obligation set forth in the 
Proposed Rule and requires public utility transmission providers to 
modify their pro forma LGIAs to effectuate the data reporting 
requirement within 12 months of the effective date of this Final Rule 
rather than the six months initially proposed.\349\ The Commission 
adopts proposed Article 8.4 of the pro forma LGIA, as modified per the 
discussion in the data reporting section. The Commission also adopts 
the proposed definition of VER. The Commission appreciates that public 
utility transmission providers in some regions, including RTOs and 
ISOs, have already implemented meteorological or forced outage 
reporting under relevant tariffs, business practices and/or markets 
rules. Such public utility transmission providers may seek to 
demonstrate in their compliance filings how continued use of these 
existing tariffs, business practices and/or market rules is adequate to 
satisfy the requirements of this Final Rule using the independent 
entity variation standard set forth in Order No. 2003, if relevant, or 
by demonstrating variations from the pro forma OATT are consistent with 
or superior to the requirements of this Final Rule.\350\
---------------------------------------------------------------------------

    \349\ See Appendix B for the revisions to the pro forma LGIA 
consistent with this Final Rule. Specifically, a new Article 8.4 and 
a new definition in Article 1 have been added to the pro forma LGIA 
and conforming revisions have been made to the table of contents.
    \350\ See Order No. 2003, FERC Stats. & Regs. ] 31,146 at P 910.
---------------------------------------------------------------------------

    376. The Commission concludes that 12 months is a reasonable amount 
of time to implement the requirements of this Final Rule. Many public 
utility transmission providers have already implemented some form of 
sub-hourly scheduling, resolving many of the issues that must be 
addressed in order to accept transmission schedules on a 15-minute 
interval. Twelve months also is an adequate amount of time for public 
utility transmission providers to determine the extent to which 
meteorological and forced outage data are necessary to support power 
production forecasting. Although we are extending the compliance 
deadline to 12 months from the compliance schedule in the Proposed 
Rule, we do not believe that more than 12 months will be necessary. 
Therefore, we will not extend the compliance deadline beyond 12 months, 
nor will we adopt commenters' other proposed recommendations.
    377. Finally, the Commission also adopts the proposal that 
transmission providers that are not public utilities must adopt the 
requirements of the Final Rule as a condition of maintaining the status 
of their safe harbor tariff or otherwise satisfying the reciprocity 
requirement of Order No. 888.\351\
---------------------------------------------------------------------------

    \351\ Order No. 888, FERC Stats. & Regs. at 31,760-63.
---------------------------------------------------------------------------

VII. Information Collection Statement

    378. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection and data retention 
requirements imposed by agency rules.\352\ Upon approval of a 
collection(s) of information, OMB will assign an OMB control number and 
an expiration date. Respondents subject to the filing requirements of a 
rule will not be penalized for failing to respond to these collections 
of information unless the collections of information display a valid 
OMB control number.
---------------------------------------------------------------------------

    \352\ 5 CFR 1320.11(b).
---------------------------------------------------------------------------

    379. The Commission is submitting the proposed modifications to its 
information collections to OMB for review and approval in accordance 
with section 3507(d) of the Paperwork Reduction Act of 1995.\353\ In 
the Proposed Rule, the Commission solicited comments on the need for 
this information, whether the information will have practical utility, 
the accuracy of provided burden estimates, ways to enhance the quality, 
utility, and clarity of the information to be collected or retained, 
and any suggested methods for minimizing the respondent's burden, 
including the use of automated information techniques. The Commission 
also included a table that listed the estimated public reporting 
burdens for the proposed reporting requirements, as well as a 
projection of the costs of compliance for the reporting requirements.
---------------------------------------------------------------------------

    \353\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    380. The Commission did not receive any comments specifically 
addressing the burden estimates provided in the Proposed Rule. However, 
commenters did respond to questions in the NOPR regarding the specific 
hardware, software, and personnel changes that are necessary to 
implement intra-hour scheduling. As noted in Section IV above, some 
parties argue that the cost to implement intra-hour scheduling will be 
modest, while other commenters state that implementation costs may be 
significant. In addition to the Commission's responses to the comments 
previously provided, the Commission believes that the revised burden 
estimates below are representative of the average burden on 
respondents.
    381. In the Final Rule, the Commission adds two burden categories 
that were not included in the Proposed Rule burden estimates. First, 
the Commission includes a burden estimate for transmission providers 
who choose to share power production forecast results with VERs. 
Second, the Commission includes a burden estimate for transmission 
providers who choose to voluntarily share VER-provided meteorological 
and forced outage data with third parties. Neither of these additional 
categories is required under the Final Rule. However, the Commission 
assumes that all Transmission Providers will implement these changes 
for the purposes of calculating a burden estimate. The Commission also 
notes that certain VERs will have increased burden due to submission of 
intra-hour schedules to transmission providers. However, the Commission 
assumes that only VERs who choose to participate in intra-hour 
scheduling are those who will receive at

[[Page 41540]]

least as much benefit as the cost that must be expended. For this 
reason, the Commission is not including a burden estimate for this 
category in the table below.
    Burden Estimate and Information Collection Costs: The estimated 
Public Reporting burden and cost for the requirements contained in this 
Final Rule follow.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Number of
Data collection FERC 516 (as contained      Number and type of      responses per      Hours per response                 Total annual hours
       in Final Rule in RM10-11)               respondents           respondent
                                        (1)......................             (2)  (3)......................  (1 x 2 x 3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Conforming tariff changes to require    142 Transmission                        1  8 first year only........  1,136 first year only.
 intra-hourly scheduling, waiver, or     Providers.\354\
 deviation request; and rate treatment
 terms for Ancillary Service.
Implementation of intra-hourly          142 Transmission                        1  30 reoccurring...........  4,260 reoccurring.
 scheduling.                             Providers.
Conforming changes to LGIA.\355\        142 Transmission                        1  20 first year only.......  2,840 first year only.
                                         Providers.
Sharing of power production             142 Transmission                        1  30 reoccurring...........  4,260 reoccurring.
 forecasting results with VER.           Providers.
Sharing of VER provided meteorological  142 Transmission                        1  30 reoccurring...........  4,260 reoccurring.
 and forced outage data with third       Providers.
 party entities (e.g. NOAA, balancing
 authority area).
Provision of meteorological and forced  160 Interconnection                     1  60 reoccurring...........  9,600 reoccurring.
 outage data to public utility           Customers with VERs per
 transmission providers for use in       year.\357\
 power production forecasting.\356\
                                       -----------------------------------------------------------------------------------------------------------------
    Totals............................  .........................  ..............  .........................  26,356 first year + reoccurring.\358\
                                                                                                             -------------------------------------------
                                                                                                              22,380 subsequent years.\359\
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Cost to Comply: The Commission has projected the total cost of 
compliance to be $3,004,584 in the first year, and $2,551,330 each year 
after.
---------------------------------------------------------------------------

    \354\ The Commission estimated in the NOPR that 134 transmission 
providers would have additional burdens due to the Proposed Rule. 
Since then, the Commission has identified eight additional 
transmission providers who are non-public utilities that file 
reciprocity open access transmission tariffs that are also expected 
to voluntarily comply with this rule.
    \355\ Consistent with the approach taken in Order No. 2003, 
public utility transmission providers with power production 
forecasting systems in place via tariff provisions and/or other 
mechanisms will be required to demonstrate that deviations from the 
pro forma LGIA are consistent with or superior to the pro forma 
LGIA.
    \356\ Once a data exchange is implemented, the Commission 
expects that this process will be automated and require little to no 
day to day burden.
    \357\ The Commission estimates that there will be approximately 
160 VERs that will sign an LGIA each year during the period from 
July 2012-July 2015 potentially subject to this requirement. This 
update from the NOPR represents more recent data.
    \358\ First year hours total 26,356, the sum of first year and 
reoccurring hours.
    \359\ Annual hours total 22,380, the sum of all reoccurring 
hours.
---------------------------------------------------------------------------

    Total Annual Hours in the first year (26,356 hours) @ $114 an hour 
[average cost of attorney ($200 per hour), consultant ($150), technical 
($80), and administrative support ($25)] = $3,004,584.
    Total Annual Hours in subsequent years (22,380 hours) @ $114 an 
hour = $2,551,320.
    Title: FERC-516, Electric Rate Schedules and Tariff Filings
    Action: Proposed Collection.
    OMB Control No. 1902-0096.
    Respondents for this Rulemaking: Transmission Providers (an RTO or 
ISO also may file some materials on behalf of its members) and Variable 
Energy Resources.
    Frequency of Information: As indicated in the table.
    Necessity of Information: The Federal Energy Regulatory Commission 
is adopting these amendments to the pro forma OATT to remedy 
operational challenges related to the increased integration of VERs to 
the bulk electric system. The purpose of this Final Rule is to 
strengthen the pro forma OATT, so VERs can be reliably and efficiently 
integrated into the electric grid and to ensure that Commission-
jurisdictional services are provided at rates, terms and conditions 
that are just and reasonable and not unduly discriminatory or 
preferential. This Final Rule seeks to achieve this goal by amending 
the pro forma OATT and LGIA to incorporate provisions that require 
intra-hourly transmission scheduling and require interconnection 
customers whose generating facilities are VERs to provide 
meteorological and operational data to public utility transmission 
providers for the purpose of power production forecasting. The 
Commission also provides guidance regarding the development of 
proposals for generator regulation service.
    Internal Review: The Commission has reviewed the proposed changes 
and has determined that the changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry. The 
Commission has assured itself, by means of internal review, that there 
is specific, objective support for the burden estimates associated with 
the information collection requirements.
    382. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director], email: 
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873. 
Comments concerning the collection of information and the associated 
burden estimate(s), may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street 
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal 
Energy Regulatory Commission, phone: (202) 395-4638, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically 
to the following email address:

[[Page 41541]]

oira_submission@omb.eop.gov. Comments submitted to OMB should include 
OMB Control No. 1902-0096 and Docket No. RM10-11-000.

VIII. Environmental Analysis

    383. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\360\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Rule under Sec.  
380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale of electric energy subject to 
the Commission's jurisdiction, plus the classification, practices, 
contracts and regulations that affect rates, charges, classifications, 
and services.\361\
---------------------------------------------------------------------------

    \360\ Regulations Implementing the National Environmental Policy 
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. 
& Regs. Preambles 1986-1990 ] 30,783 (1987).
    \361\ 18 CFR 380.4(a)(15) (2010).
---------------------------------------------------------------------------

IX. Regulatory Flexibility Act Analysis

    384. The Regulatory Flexibility Act of 1980 (RFA) \362\ generally 
requires a description and analysis of Final Rules that will have a 
significant economic impact on a substantial number of small entities. 
This Final Rule applies to public utilities that own, control or 
operate interstate transmission facilities \363\ and to variable energy 
resources. The total estimated number of small public utility 
transmission providers \364\ impacted by this Final Rule is estimated 
to be ten. The Commission assumes that the Final Rule will impact all 
the applicable small transmission providers equally at an average cost 
of $13,500 per year. The Commission does not consider this to be a 
significant economic impact. In any event, each of these entities may 
seek waiver of these requirements.\365\ The Commission estimates that 
all of the applicable VERs (160 per year) are small. Of these 160 
entities, approximately 100 that are greater than 20 MW will be 
required to comply with the Final Rule and approximately 60 that are 20 
MW or less will have the option to comply with the rule. The Commission 
estimates that each VER will have an average cost of $6,800 per year 
because of the Final Rule. The Commission does not consider this to be 
a significant economic impact on these small entities. The costs 
incurred by VERs due to this rule are offset by an expected reduction 
in energy imbalance penalties that will be assessed to VERs in the 
future due to improved forecasting and reduced uncertainty across 15-
minute scheduling periods compared to hour-long scheduling periods. 
Accordingly, the Commission certifies that this Final Rule will not 
have a significant economic impact on a substantial number of small 
entities.
---------------------------------------------------------------------------

    \362\ 5 U.S.C. 601-612 (2006).
    \363\ Other than those that have received waiver of the 
obligation to comply with Order Nos. 888, 889, and 890.
    \364\ A ``small entity'' as referenced in the RFA refers to the 
definition provided in section 3 of the Small Business Act where a 
firm is ``small'' if, including its affiliates, it is primarily 
engaged in the generation, transmission, and/or distribution of 
electric energy for sale and its total electric output for the 
preceding fiscal year did not exceed 4 million megawatt hours.
    \365\ The criteria for waiver that would be applied under this 
rulemaking for small entities is unchanged from that used to 
evaluate requests for waiver under Order Nos. 888, 889, and 890.
---------------------------------------------------------------------------

X. Document Availability

    385. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (https://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5:00 
p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 
20426.
    386. From FERC's Home Page on the Internet, this information is 
available on eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type the docket 
number excluding the last three digits of this document in the docket 
number field.
    387. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

XI. Effective Date and Congressional Notification

    388. These regulations are effective September 11, 2012. The 
Commission has determined, with the concurrence of the Administrator of 
the Office of Information and Regulatory Affairs of OMB, that this rule 
is not a ``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996. The Commission will submit 
this Final Rule to both houses of Congress and the Government 
Accountability Office.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

By the Commission. Commissioner LaFleur is dissenting in part with a 
separate statement attached.

    Commissioner Clark voting present.

Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission amends Part 35, 
Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for Part 35 continues to read as follows:

    Authority:  16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 71-7352.


0
2. Amend Sec.  35.28 as follows:
0
a. Paragraphs (c)(1) introductory text and (c)(1)(i) through 
(c)(1)(iii) are revised.
0
b. Paragraphs (c)(1)(v) and (c)(1)(vi) are revised.
0
c. Paragraphs (c)(3) introductory text and (c)(3)(ii) are revised.
0
d. Paragraph (c)(4) is revised.
0
e. Paragraph (d) is revised.
0
f. Paragraphs (e)(1) introductory text, (e)(1)(ii), and (e)(2) are 
revised.
0
g. Paragraphs (f)(1) introductory text and (f)(1)(i) are revised.
0
h. Paragraphs (f)(1)(ii) through (f)(1)(iv) are removed and reserved.
0
i. Paragraph (f)(3) is revised.
0
j. Paragraph (f)(4) is removed.


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (c) Non-discriminatory open access transmission tariffs.
    (1) Every public utility that owns, controls, or operates 
facilities used for the transmission of electric energy in interstate 
commerce must have on file with the Commission an open access 
transmission tariff of general applicability for transmission services, 
including ancillary services, over such facilities. Such tariff must be 
the pro forma tariff promulgated by the Commission, as amended from 
time to time, or such other tariff as may be approved by the Commission 
consistent with the principles set forth in Commission rulemaking 
proceedings promulgating and amending the pro forma tariff.

[[Page 41542]]

    (i) Subject to the exceptions in paragraphs (c)(1)(ii), 
(c)(1)(iii), (c)(1)(iv), and (c)(1)(v) of this section, the open access 
transmission tariff, which tariff must be the pro forma tariff required 
by Commission rulemaking proceedings promulgating and amending the pro 
forma tariff, and accompanying rates must be filed no later than 60 
days prior to the date on which a public utility would engage in a sale 
of electric energy at wholesale in interstate commerce or in the 
transmission of electric energy in interstate commerce.
    (ii) If a public utility owns, controls, or operates facilities 
used for the transmission of electric energy in interstate commerce, it 
must file the revisions to its open access transmission tariff required 
by Commission rulemaking proceedings promulgating and amending the pro 
forma tariff, pursuant to section 206 of the FPA and accompanying rates 
pursuant to section 205 of the FPA in accordance with the procedures 
set forth in Commission rulemaking proceedings promulgating and 
amending the pro forma tariff.
    (iii) If a public utility owns, controls, or operates transmission 
facilities used for the transmission of electric energy in interstate 
commerce, such facilities are jointly owned with a non-public utility, 
and the joint ownership contract prohibits transmission service over 
the facilities to third parties, the public utility with respect to 
access over the public utility's share of the jointly owned facilities 
must file the revisions to its open access transmission tariff required 
by Commission rulemaking proceedings promulgating and amending the pro 
forma tariff pursuant to section 206 of the FPA and accompanying rates 
pursuant to section 205 of the FPA in accordance with the procedures 
set forth in Commission rulemaking proceedings promulgating and 
amending the pro forma tariff.
* * * * *
    (v) If a public utility obtains a waiver of the tariff requirement 
pursuant to paragraph (d) of this section, it does not need to file the 
open access transmission tariff required by this section.
    (vi) Any public utility that seeks a deviation from the pro forma 
tariff promulgated by the Commission, as amended from time to time, 
must demonstrate that the deviation is consistent with the principles 
set forth in Commission rulemaking proceedings promulgating and 
amending the pro forma tariff.
* * * * *
    (3) Every public utility that owns, controls, or operates 
facilities used for the transmission of electric energy in interstate 
commerce, and that is a member of a power pool, public utility holding 
company, or other multi-lateral trading arrangement or agreement that 
contains transmission rates, terms or conditions, must have on file a 
joint pool-wide or system-wide open access transmission tariff, which 
tariff must be the pro forma tariff promulgated by the Commission, as 
amended from time to time, or such other open access transmission 
tariff as may be approved by the Commission consistent with the 
principles set forth in Commission rulemaking proceedings promulgating 
and amending the pro forma tariff.
* * * * *
    (ii) For any power pool, public utility holding company or other 
multi-lateral arrangement or agreement that contains transmission 
rates, terms or conditions and that is executed on or before May 14, 
2007, a public utility member of such power pool, public utility 
holding company or other multi-lateral arrangement or agreement that 
owns, controls, or operates facilities used for the transmission of 
electric energy in interstate commerce must file the revisions to its 
joint pool-wide or system-wide open access transmission tariff required 
by Commission rulemaking proceedings promulgating and amending the pro 
forma tariff pursuant to section 206 of the FPA and accompanying rates 
pursuant to section 205 of the FPA in accordance with the procedures 
set forth in Commission rulemaking proceedings promulgating and 
amending the pro forma tariff.
* * * * *
    (4) Consistent with paragraph (c)(1) of this section, every 
Commission-approved ISO or RTO must have on file with the Commission an 
open access transmission tariff of general applicability for 
transmission services, including ancillary services, over such 
facilities. Such tariff must be the pro forma tariff promulgated by the 
Commission, as amended from time to time, or such other tariff as may 
be approved by the Commission consistent with the principles set forth 
in Commission rulemaking proceedings promulgating and amending the pro 
forma tariff.
    (i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to its open access 
transmission tariff required by Commission rulemaking proceedings 
promulgating and amending the pro forma tariff pursuant to section 206 
of the FPA and accompanying rates pursuant to section 205 of the FPA in 
accordance with the procedures set forth in Commission rulemaking 
proceedings promulgating and amending the pro forma tariff.
    (ii) If a Commission-approved ISO or RTO can demonstrate that its 
existing open access transmission tariff is consistent with or superior 
to the pro forma tariff promulgated by the Commission, as amended from 
time to time, the Commission-approved ISO or RTO may instead set forth 
such demonstration in its filing pursuant to section 206 in accordance 
with the procedures set forth in Commission rulemaking proceedings 
promulgating and amending the pro forma tariff.
    (d) Waivers. A public utility subject to the requirements of this 
section and Order No. 889, FERC Stats. & Regs. ] 31,037 (Final Rule on 
Open Access Same-Time Information System and Standards of Conduct) may 
file a request for waiver of all or part of the requirements of this 
section, or Part 37 (Open Access Same-Time Information System and 
Standards of Conduct for Public Utilities), for good cause shown. 
Except as provided in paragraph (f) of this section, an application for 
waiver must be filed no later than 60 days prior to the time the public 
utility would have to comply with the requirement.
    (e) Non-public utility procedures for tariff reciprocity 
compliance.
    (1) A non-public utility may submit an open access transmission 
tariff and a request for declaratory order that its voluntary 
transmission tariff meets the requirements of Commission rulemaking 
proceedings promulgating and amending the pro forma tariff.
* * * * *
    (ii) If the submittal is found to be an acceptable open access 
transmission tariff, an applicant in a Federal Power Act (FPA) section 
211 or 211A proceeding against the non-public utility shall have the 
burden of proof to show why service under the open access transmission 
tariff is not sufficient and why a section 211 or 211A order should be 
granted.
    (2) A non-public utility may file a request for waiver of all or 
part of the reciprocity conditions contained in a public utility open 
access transmission tariff, for good cause shown. An application for 
waiver may be filed at any time.
    (f) Standard generator interconnection procedures and agreements.
    (1) Every public utility that is required to have on file a non-
discriminatory open access transmission tariff under this section must 
amend such tariff by adding the standard interconnection procedures and

[[Page 41543]]

agreement and the standard small generator interconnection procedures 
and agreement required by Commission rulemaking proceedings 
promulgating and amending such interconnection procedures and 
agreements, or such other interconnection procedures and agreements as 
may be required by Commission rulemaking proceedings promulgating and 
amending the standard interconnection procedures and agreement and the 
standard small generator interconnection procedures and agreement.
    (i) Any public utility that seeks a deviation from the standard 
interconnection procedures and agreement or the standard small 
generator interconnection procedures and agreement required by 
Commission rulemaking proceedings promulgating and amending such 
interconnection procedures and agreements, must demonstrate that the 
deviation is consistent with the principles set forth in Commission 
rulemaking proceedings promulgating and amending such interconnection 
procedures and agreements.
* * * * *
    (3) A public utility subject to the requirements of this paragraph 
(f) may file a request for waiver of all or part of the requirements of 
this paragraph (f), for good cause shown.
* * * * *

    Note:  The following appendices will not be published in the 
Code of Federal Regulations.

Appendix A: List of Short Names of Commenters on the Federal Energy 
Regulatory Commission's Notice of Proposed Rulemaking on Integration of 
Variable Energy Resources--Docket No. RM10-11-000, November 2010

------------------------------------------------------------------------
    Short name or acronym                      Commenter
------------------------------------------------------------------------
A123.........................  A123 Systems, Inc.
AEP..........................  American Electric Power Service
                                Corporation
ALLETE.......................  ALLETE Inc.
ACSF.........................  American Clean Skies Foundation
Alstom.......................  Alstom Grid, Inc.
American Gas.................  American Gas Association
APPA.........................  American Public Power Association
Argonne National Lab.........  Argonne National Laboratory
Arizona Corporation            Arizona Corporation Commission
 Commission.
Avista.......................  Avista Corporation
AWEA.........................  American Wind Energy Association
Beacon Power.................  Beacon Power Corporation
Bonneville Power.............  Bonneville Power Administration
BP Companies.................  BP Energy Company and BP Wind Energy
                                North America, Inc.
BrightSource.................  BrightSource Energy, Inc.
Business Council.............  Business Council for Sustainable Energy
CESA.........................  California Energy Storage Alliance
California State Water         California Department of Water Resources
 Project.                       State Water Project
California ISO...............  California Independent System Operator
                                Corporation
California PUC...............  California Public Utilities Commission
CEERT........................  Center for Energy Efficiency and
                                Renewable Technologies
Center for Rural Affairs.....  Center for Rural Affairs
CMUA.........................  California Municipal Utilities
                                Association; Cities of Alameda, Anaheim,
                                Azusa, Banning, Burbank, Cerritos,
                                Colton, Corona, Glendale, Gridley,
                                Healdsburg, Hercules, Lodi, Lompoc,
                                Moreno Valley, Needles, Palo Alto,
                                Pasadena, Pittsburg, Rancho Cucamonga,
                                Redding, Riverside, Roseville, Santa
                                Clara, Shasta Lake, Ukiah, and Vernon;
                                the Imperial, Merced, Modesto, and
                                Turlock Irrigation Districts; the
                                Northern California Power Agency;
                                Southern California Public Power
                                Authority; Transmission Agency of
                                Northern California; Lassen Municipal
                                Utility District; Power and Water
                                Resources Pooling Authority; Sacramento
                                Municipal Utility District; the Trinity
                                and Truckee Donner Public Utility
                                Districts; the Metropolitan Water
                                District of Southern California; and the
                                City and County of San Francisco, Hetch-
                                Hetchy
Clean Line...................  Clean Line Energy Partners, LLC
CGC..........................  Coalition for Green Capital
Defenders of Wildlife........  Wilderness Society and Defenders of
                                Wildlife
Detroit Edison...............  Detroit Edison Company
Dominion.....................  Dominion Resources Services, Inc.
Duke.........................  Duke Energy Corporation
EEI..........................  Edison Electric Institute
ELCON........................  Electricity Consumers Resource Council
EPSA.........................  Electric Power Supply Association
ENBALA.......................  ENBALA Power Networks
Entergy......................  Entergy Services, Inc.
Environmental Defense Fund...  Environmental Defense Fund
E.ON C&R.....................  E.ON Climate & Renewables North America
Exelon.......................  Exelon Corporation
Federal Trade Commission.....  Federal Trade Commission
FirstEnergy..................  FirstEnergy Service Company
First Wind...................  First Wind Energy, LLC
FriiPwr......................  FriiPwr USA Ltd
Grant PUD....................  Public Utility District No. 2 of Grant
                                County, Washington
Grays Harbor PUD.............  Public Utility District No. 1 of Grays
                                Harbor County, Washington
Iberdrola....................  Iberdrola Renewables, Inc.
Idaho Power..................  Idaho Power Company
Independent Energy Producers.  Independent Energy Producers Association

[[Page 41544]]

 
Independent Power Producers    Arizona Competitive Power Alliance;
 Coalition-West.                Colorado Independent Energy Association;
                                Independent Energy Producers Association
                                (California); New Mexico Independent
                                Power Producers Coalition; and the
                                Northwest & Intermountain Power
                                Producers Coalition.
INGAA........................  Interstate Natural Gas Association of
                                America
Invenergy Wind...............  Invenergy Wind Development LLC
ISO New England..............  ISO New England Inc. and the New England
                                Power Pool
ISO/RTO Council..............  Alberta Electricity System Operator;
                                California Independent System Operator;
                                Electric Reliability Council of Texas;
                                Independent Electricity System Operator
                                of Ontario; ISO New England, Inc.;
                                Midwest Independent Transmission System
                                Operator, Inc.; New Brunswick System
                                Operator; New York Independent System
                                Operator, Inc.; PJM Interconnection,
                                L.L.C.; and Southwest Power Pool, Inc.
ITC Companies................  ITCTransmission; Michigan Electric
                                Transmission Company, LLC; ITC Midwest
                                LLC; and ITC Great Plains, LLC
Joint Parties................  Arizona Public Service Company; The
                                Boeing Company, El Paso Electric; New
                                York Independent System Operator; Old
                                Dominion Electric Cooperative; PJM
                                Interconnection, L.L.C.; Salt River
                                Project Agriculture Improvement and
                                Power District; Southwest Power Pool;
                                Tennessee Valley Authority; Tucson
                                Electric Power Company; UNS Gas, Inc.;
                                and the Vermont Department of Public
                                Service
Joint Initiative.............  Joint Initiative Facilitators
Large Public Power Council...  Austin Energy; Chelan County Public
                                Utility District No. 1; Clark Public
                                Utilities, Colorado Springs Utilities;
                                CPS Energy (San Antonio); ElectriCities
                                of North Carolina; Grant County Public
                                Utility District; IID Energy (Imperial
                                Irrigation District); JEA (Jacksonville,
                                FL); Long Island Power Authority; Los
                                Angeles Department of Water and Power;
                                Lower Colorado River Authority; MEAG
                                Power; Nebraska Public Power District;
                                New York Power Authority; Omaha Public
                                Power District; Orlando Utilities
                                Commission; Platte River Power
                                Authority; Puerto Rico Electric Power
                                Authority; Sacramento Municipal Utility
                                District; Salt River Project; Santee
                                Cooper; Seattle City Light; Snohomish
                                County Public Utility District No. 1;
                                and Tacoma Public Utilities
LADWP........................  Department of Water and Power of the City
                                of Los Angeles
Massachusetts DPU............  Massachusetts Department of Public
                                Utilities
MidAmerican..................  MidAmerican Energy Holdings Company
Midwest Energy...............  Midwest Energy, Inc.
Midwest ISO..................  Midwest Independent Transmission System
                                Operator, Inc.
Midwest ISO Transmission       Ameren Services Company, as agent for
 Owners.                        Union Electric Company d/b/a Ameren
                                Missouri; Ameren Illinois Company d/b/a
                                Ameren Illinois and Ameren Transmission
                                Company of Illinois; American
                                Transmission Company LLC; Big Rivers
                                Electric Corporation; City Water, Light
                                & Power (Springfield, IL); Dairyland
                                Power Cooperative; Duke Energy
                                Corporation for Duke Energy Ohio, Inc.,
                                Duke Energy Indiana, Inc., and Duke
                                Energy Kentucky, Inc.; Great River
                                Energy; Hoosier Energy Rural Electric
                                Cooperative, Inc. (``Hoosier''); Indiana
                                Municipal Power Agency; Indianapolis
                                Power & Light Company (``IPL'');
                                Michigan Public Power Agency;
                                MidAmerican Energy Company; Minnesota
                                Power (and its subsidiary Superior
                                Water, L&P); Montana-Dakota Utilities
                                Co.; Northern Indiana Public Service
                                Company; Northern States Power Company,
                                a Minnesota corporation, and Northern
                                States Power Company, a Wisconsin
                                corporation, subsidiaries of Xcel Energy
                                Inc. (``Xcel Energy''); NorthWestern
                                Wisconsin Electric Company; Otter Tail
                                Power Company; Southern Illinois Power
                                Cooperative; Southern Indiana Gas &
                                Electric Company (d/b/a Vectren Energy
                                Delivery of Indiana); Southern Minnesota
                                Municipal Power Agency; Wabash Valley
                                Power Association, Inc.; and Wolverine
                                Power Supply Cooperative, Inc.
M-S-R Public Power Agency....  Modesto Irrigation District; City of
                                Santa Clara, California; and City of
                                Redding, California
Montana PSC..................  Montana Public Service Commission
NEMA.........................  National Electrical Manufacturers
                                Association
National Grid................  National Grid USA
NRECA........................  National Rural Electric Cooperative
                                Association
Natural Gas..................  Natural Gas Supply Association
NaturEner....................  NaturEner USA, LLC
NE Conference of PUCs........  New England Conference of Public
                                Utilities Commissioners
NESCOE.......................  New England States Committee on
                                Electricity
NV Energy....................  Nevada Power Company and Sierra Pacific
                                Power Company
New York ISO.................  New York Independent System Operator,
                                Inc.
NextEra......................  NextEra Energy, Inc.
NERC.........................  North American Electric Reliability
                                Corporation
NAESB........................  North American Energy Standards Board
NOAA.........................  National Oceanic and Atmospheric
                                Administration
NorthWestern.................  NorthWestern Corporation
Organization of Midwest ISO    Organization of Midwest ISO States
 States.
Oregon & New Mexico PUC......  Public Utility Commissioners of Oregon
                                and New Mexico and Paul Newman, Arizona
                                Commissioner
Pacific Gas & Electric.......  Pacific Gas and Electric Company
PNW Parties..................  Avista Corporation; the Bonneville Power
                                Administration; Idaho Power Company;
                                NorthWestern Corporation, dba
                                NorthWestern Energy; PacifiCorp;
                                Portland General Electric Company; the
                                Public Generating Pool (Tacoma Power,
                                Eugene Water and Electric Board, and
                                Public Utility Districts for Chelan,
                                Clark, Cowlitz, Douglas, Grant,
                                Klickitat, Pend Oreille, and Snohomish
                                counties); the Public Power Council;
                                Puget Sound Energy, Inc.; and Seattle
                                City Light

[[Page 41545]]

 
PJM..........................  PJM Interconnection, L.L.C.
Powerex......................  Powerex Corporation
Public Interest Organizations  Alliance for Clean Energy New York;
                                Center for Rural Affairs; Citizens
                                Utility Board of Wisconsin; Climate and
                                Energy Project; Conservation Law
                                Foundation; Defenders of Wildlife;
                                Energy Conservation Council of
                                Pennsylvania; Energy Future Coalition;
                                Environment Northeast; Environmental
                                Defense Fund; Environmental Law & Policy
                                Center; Fresh Energy; Great Plains
                                Institute; Natural Resources Defense
                                Council; Office of the Ohio Consumers'
                                Counsel; Pace Energy and Climate Center;
                                Project for Sustainable FERC Energy
                                Policy; Sierra Club; The Wilderness
                                Society; Union of Concerned Scientists;
                                Western Grid Group; Western Resource
                                Advocates; and Wind on the Wires
Public Power Council.........  Public Power Council
Puget........................  Puget Sound Energy, Inc.
Recycled Energy..............  Recycled Energy Development
RENEW........................  Renewable Energy New England, Inc.
RenewElec....................  The RenewElec Project
SMUD.........................  Sacramento Municipal Utility District
San Diego Gas & Electric.....  San Diego Gas & Electric Company
Snohomish County PUD.........  Public Utility District No. 1 of
                                Snohomish County, Washington
SEIA.........................  Solar Energy Industries Association and
                                the Large-Scale Solar Association
Southern California Edison...  Southern California Edison Company
Southern.....................  Southern Company Services, Inc.
Southern MN Municipal........  Southern Minnesota Municipal Power Agency
SWEA.........................  Southwest Energy Alliance
Southwestern.................  Southwestern Power Administration
Spectra Entities.............  Spectra Energy Transmission, LLC and
                                Spectra Energy Partners, LP
Sunflower and Mid-Kansas.....  Sunflower Electric Power Corporation and
                                Mid-Kansas Electric Company, LLC
TA Miller....................  T.A. Miller
Tacoma Power.................  City of Tacoma, Department of Public
                                Utilities, Light Division (Washington)
Tres Amigas..................  Tres Amigas LLC
TVA..........................  Tennessee Valley Authority
US Bureau of Reclamation.....  United States Bureau of Reclamation
Utility Economic Engineers...  Utility Economic Engineers
Vestas.......................  Vestas-American Wind Technology, Inc.
Viridity Energy..............  Viridity Energy, Inc.
Vote Solar...................  Vote Solar Initiative
WUTC.........................  Washington Utilities and Transportation
                                Commission
WestConnect..................  Arizona Public Service Company; El Paso
                                Electric Company, Imperial Irrigation
                                District; NV Energy, Public Service
                                Company of Colorado; Public Service
                                Company of New Mexico; Sacramento
                                Municipal Utility District; Salt River
                                Project; Southwest Transmission
                                Cooperative, Inc.; Transmission Agency
                                of Northern California; Tri-State
                                Generation and Transmission Association,
                                Inc.; Tucson Electric Power Company and
                                Western Area Power Administration
Western Farmers..............  Western Farmers Electric Cooperative
Western Grid.................  Western Grid Group
Xcel.........................  Xcel Energy Services Inc.
Xtreme Power.................  Xtreme Power Inc.
------------------------------------------------------------------------

Appendix B: Pro Forma Open Access Transmission Tariff

    The Commission amends the following sections of the pro forma 
OATT:

a. Section 13.8
b. Section 14.6

    13.8 Scheduling of Firm Point-To-Point Transmission Service: 
Schedules for the Transmission Customer's Firm Point-To-Point 
Transmission Service must be submitted to the Transmission Provider 
no later than 10:00 a.m. [or a reasonable time that is generally 
accepted in the region and is consistently adhered to by the 
Transmission Provider] of the day prior to commencement of such 
service. Schedules submitted after 10:00 a.m. will be accommodated, 
if practicable. Hour-to-hour and intra-hour (four intervals 
consisting of fifteen minute schedules) schedules of any capacity 
and energy that is to be delivered must be stated in increments of 
1,000 kW per hour [or a reasonable increment that is generally 
accepted in the region and is consistently adhered to by the 
Transmission Provider]. Transmission Customers within the 
Transmission Provider's service area with multiple requests for 
Transmission Service at a Point of Receipt, each of which is under 
1,000 kW per hour, may consolidate their service requests at a 
common point of receipt into units of 1,000 kW per hour for 
scheduling and billing purposes. Scheduling changes will be 
permitted up to twenty (20) minutes [or a reasonable time that is 
generally accepted in the region and is consistently adhered to by 
the Transmission Provider] before the start of the next scheduling 
interval provided that the Delivering Party and Receiving Party also 
agree to the schedule modification. The Transmission Provider will 
furnish to the Delivering Party's system operator, hour-to-hour and 
intra-hour schedules equal to those furnished by the Receiving Party 
(unless reduced for losses) and shall deliver the capacity and 
energy provided by such schedules. Should the Transmission Customer, 
Delivering Party or Receiving Party revise or terminate any 
schedule, such party shall immediately notify the Transmission 
Provider, and the Transmission Provider shall have the right to 
adjust accordingly the schedule for capacity and energy to be 
received and to be delivered.
    14.6 Scheduling of Non-Firm Point-To-Point Transmission Service: 
Schedules for Non-Firm Point-To-Point Transmission Service must be 
submitted to the Transmission Provider no later than 2:00 p.m. [or a 
reasonable time that is generally accepted in the region and is 
consistently adhered to by the Transmission Provider] of the day 
prior to commencement of such service. Schedules submitted after 
2:00 p.m. will be accommodated, if practicable. Hour-to-hour and 
intra-hour (four intervals consisting of fifteen minute schedules) 
schedules of energy that is to be delivered must be stated in 
increments of 1,000 kW per hour [or a reasonable increment that is 
generally accepted in the region and is consistently adhered to by 
the Transmission Provider]. Transmission Customers within

[[Page 41546]]

the Transmission Provider's service area with multiple requests for 
Transmission Service at a Point of Receipt, each of which is under 
1,000 kW per hour, may consolidate their schedules at a common Point 
of Receipt into units of 1,000 kW per hour. Scheduling changes will 
be permitted twenty (20) minutes [or a reasonable time that is 
generally accepted in the region and is consistently adhered to by 
the Transmission Provider] before the start of the next scheduling 
interval, provided that the Delivering Party and Receiving Party 
also agree to the schedule modification. The Transmission Provider 
will furnish to the Delivering Party's system operator, hour-to-hour 
and intra-hour schedules equal to those furnished by the Receiving 
Party (unless reduced for losses) and shall deliver the capacity and 
energy provided by such schedules. Should the Transmission Customer, 
Delivering Party or Receiving Party revise or terminate any 
schedule, such party shall immediately notify the Transmission 
Provider, and the Transmission Provider shall have the right to 
adjust accordingly the schedule for capacity and energy to be 
received and to be delivered.

Appendix C: Pro Forma Large Generator Interconnection Agreement

    The Commission amends and/or adds the following sections of the 
pro forma LGIA:
    a. Table of Contents (Add Article 8.4, Provision of Data from a 
Variable Energy Resource)
    b. Article 1 (Add definition of Variable Energy Resource)
    c. Article 8.4

Article 1 Definition

    Variable Energy Resource shall mean a device for the production 
of electricity that is characterized by an energy source that: (1) 
Is renewable; (2) cannot be stored by the facility owner or 
operator; and (3) has variability that is beyond the control of the 
facility owner or operator.

Article 8.4 Provision of Data From a Variable Energy Resource

    The Interconnection Customer whose Generating Facility is a 
Variable Energy Resource shall provide meteorological and forced 
outage data to the Transmission Provider to the extent necessary for 
the Transmission Provider's development and deployment of power 
production forecasts for that class of Variable Energy Resources. 
The Interconnection Customer with a Variable Energy Resource having 
wind as the energy source, at a minimum, will be required to provide 
the Transmission Provider with site-specific meteorological data 
including: temperature, wind speed, wind direction, and atmospheric 
pressure. The Interconnection Customer with a Variable Energy 
Resource having solar as the energy source, at a minimum, will be 
required to provide the Transmission Provider with site-specific 
meteorological data including: temperature, atmospheric pressure, 
and irradiance. The Transmission Provider and Interconnection 
Customer whose Generating Facility is a Variable Energy Resource 
shall mutually agree to any additional meteorological data that are 
required for the development and deployment of a power production 
forecast. The Interconnection Customer whose Generating Facility is 
a Variable Energy Resource also shall submit data to the 
Transmission Provider regarding all forced outages to the extent 
necessary for the Transmission Provider's development and deployment 
of power production forecasts for that class of Variable Energy 
Resources. The exact specifications of the meteorological and forced 
outage data to be provided by the Interconnection Customer to the 
Transmission Provider, including the frequency and timing of data 
submittals, shall be made taking into account the size and 
configuration of the Variable Energy Resource, its characteristics, 
location, and its importance in maintaining generation resource 
adequacy and transmission system reliability in its area. All 
requirements for meteorological and forced outage data must be 
commensurate with the power production forecasting employed by the 
Transmission Provider. Such requirements for meteorological and 
forced outage data are set forth in Appendix C, Interconnection 
Details, of this LGIA, as they may change from time to time.

LaFLEUR, Commissioner, dissenting in part:

    I am dissenting in part on this Final Rule.
    I strongly support renewable energy, and I have stated many times 
that I believe one of the most important jobs of this Commission is to 
support the development of rules to address new power supply choices 
being made at the state and federal level. For that reason, I support 
the requirements in the rule for intra-hour scheduling and power 
production forecasting, as well as the guidance we provide on generator 
regulation service charges.
    I am dissenting on the narrow point of the compliance requirements 
in the Final Rule. As noted in the rule, we heard from many parties 
about ongoing efforts to establish intra-hour scheduling and other 
market improvements in various regions. However, the rule as issued 
would only allow parties to demonstrate compliance through incremental 
reforms beyond those already underway, without any explanation of why 
the ongoing efforts are insufficient. I would give regions more 
flexibility to demonstrate on compliance that these ongoing efforts 
meet the objectives of the rule.
    Accordingly, I respectfully dissent in part.

Cheryl A. LaFleur,
Commissioner.

[FR Doc. 2012-15762 Filed 7-12-12; 8:45 am]
BILLING CODE 6717-01-P