Integration of Variable Energy Resources, 75336-75361 [2010-29574]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 75, Number 231 (Thursday, December 2, 2010)]
[Proposed Rules]
[Pages 75336-75361]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-29574]



[[Page 75335]]

-----------------------------------------------------------------------

Part IV





Department of Energy





-----------------------------------------------------------------------



 Federal Energy Regulatory Commission



-----------------------------------------------------------------------



18 CFR Part 35



Integration of Variable Energy Resources; Proposed Rule

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

[[Page 75336]]


-----------------------------------------------------------------------

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM10-11-000]


Integration of Variable Energy Resources

November 18, 2010.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

-----------------------------------------------------------------------

SUMMARY: In this Notice of Proposed Rulemaking, the Federal Energy 
Regulatory Commission proposes to reform the pro forma Open Access 
Transmission Tariff to remove unduly discriminatory practices and to 
ensure just and reasonable rates for Commission-jurisdictional 
services. Accordingly, the Proposed Rule would: require public utility 
transmission providers to offer intra-hourly transmission scheduling; 
incorporate provisions into the pro forma Large Generator 
Interconnection Agreement requiring interconnection customers whose 
generating facilities are variable energy resources to provide 
meteorological and operational data to public utility transmission 
providers for the purpose of power production forecasting; and add a 
generic ancillary service rate schedule through which public utility 
transmission providers will offer regulation service to transmission 
customers delivering energy from a generator located within the 
transmission provider's balancing authority area. The proposed reforms 
will remove barriers to the integration of variable energy resources.

DATES: Comments are due January 31, 2011.

ADDRESSES: You may submit comments, identified by docket number and in 
accordance with the requirements posted on the Commission's Web site, 
https://www.ferc.gov. Comments may be submitted by any of the following 
methods:
     Agency Web site: Documents created electronically using 
word processing software should be filed in native applications or 
print-to-PDF format, and not in a scanned format, at https://www.ferc.gov/docs-filing/efiling.asp.
     Mail/Hand Delivery: Commenters unable to file comments 
electronically must mail or hand deliver an original copy of their 
comments to: Federal Energy Regulatory Commission, Secretary of the 
Commission, 888 First Street, NE., Washington, DC 20426. These 
requirements can be found on the Commission's Web site, see, e.g., the 
``Quick Reference Guide for Paper Submissions,'' available at https://www.ferc.gov/docs-filing/efiling.asp, or via phone from FERC Online 
Support at 202-502-6652 or toll-free at 1-866-208-3676.

FOR FURTHER INFORMATION CONTACT: 
Mk Shean (Technical Information), Office of Energy Policy and 
Innovation, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-6792, Mk.Shean@ferc.gov;
Andrea Hilliard (Legal Information), Office of General Counsel--Energy 
Markets, Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8288, Andrea.Hilliard@ferc.gov.

SUPPLEMENTARY INFORMATION:

                            Table of Contents
------------------------------------------------------------------------
                                                              Paragraph/
                                                                 Nos.
------------------------------------------------------------------------
I. Introduction.............................................           1
II. Background..............................................           6
III. The Need for Reform....................................          12
IV. Summary of Proposed Reforms.............................          19
V. Proposed Reforms.........................................          25
    A. Intra-hourly Scheduling..............................          25
    B. Power Production Forecasting and Data Reporting......          45
    C. Generator Regulation Service-Capacity................          66
VI. Compliance Filings......................................         101
VII. Information Collection Statement.......................         108
VIII. Environmental Analysis................................         112
IX. Regulatory Flexibility Act Analysis.....................         113
X. Comment Procedures.......................................         115
XI. Document Availability...................................         119
Regulatory Text
Appendix A: List of Short Names of Commenters on the Federal
 Energy Regulatory Commission's Notice of Inquiry on
 Integration of Variable Energy Resources--Docket No. RM10-
 11-000, January 2010
Appendix B: Proposed inserts to the Pro Forma Open Access
 Transmission Tariff
Appendix C: Proposed inserts to the Pro Forma Large
 Generator Interconnection Agreement
------------------------------------------------------------------------

I. Introduction

    1. In this Notice of Proposed Rulemaking (Proposed Rule), the 
Federal Energy Regulatory Commission (Commission) proposes reforms to 
the pro forma Open Access Transmission Tariff (OATT) that derive from 
the Integration of Variable Energy Resources Notice of Inquiry.\1\ The 
Commission initiated that inquiry to obtain information on barriers to 
the integration of variable energy resources (VER) \2\ and on the 
current state of VER integration in various regions of the country. Not 
unexpectedly, commenters indicate that VER presence is not uniform 
throughout the country. Commenters also describe their experiences 
integrating VERs and the on-going industry efforts designed to address 
issues posed by increasing numbers of VERs. Many of these industry 
efforts are significant in scope and have the potential to address 
issues confronting regions where large

[[Page 75337]]

concentrations of VERs are located.\3\ Accordingly, in the Proposed 
Rule, the Commission has decided to propose a limited set of reforms to 
existing operational procedures that we preliminarily find to be unduly 
discriminatory and leading to unjust and unreasonable rates for 
transmission service. Specifically, the Proposed Rule addresses 
transmission scheduling practices, VER power production forecasts, and 
the recovery of capacity charges associated with generator imbalance 
service (i.e., generator regulation service).
---------------------------------------------------------------------------

    \1\ Integration of Variable Energy Resources, 130 FERC ] 61,053 
(2010) (Integrating VERs NOI).
    \2\ For the purpose of this proceeding, the term variable energy 
resource (VER) refers to an electric generating facility that is 
characterized by an energy source that: (1) Is renewable; (2) cannot 
be stored by the facility owner or operator; and (3) has variability 
that is beyond the control of the facility owner or operator. This 
includes, for example, wind, solar thermal and photovoltaic, and 
hydrokinetic generating facilities.
    \3\ See, e.g., Joint Initiative at 1-12 (describing 
collaborative efforts in the Western Interconnection for high-value 
and cost-effective regional products involving increased 
coordination among different transmission providers), SMUD at 8-12 
(describing SMUD's participation in regional efforts in California 
and the Northwest), ISO/RTO Council at 12-18 (discussing ISO/RTO 
efforts to develop and incorporate VER forecasting into their system 
operations).
---------------------------------------------------------------------------

    2. In Order No. 890, the Commission made several reforms to the pro 
forma OATT, recognizing that the mix of generation resources on the 
system was changing and that not all generation resources were 
similarly situated.\4\ The Commission recognized that intermittent 
resources, such as wind power, have a limited ability to control their 
output, and that this limitation supports tailoring certain 
requirements to the special circumstances presented by this type of 
resource.\5\ Similarly, the Commission preliminarily finds that the 
practice of hourly scheduling, the lack of VER power production 
forecasting, and the lack of a clear mechanism to recover the cost of 
providing generator regulation service may be contributing to undue 
discrimination and unjust and unreasonable rates in light of the entry 
and increasing presence of VERs on the transmission grid.
---------------------------------------------------------------------------

    \4\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241, 
at P 5, order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 
31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 
(2008), order on reh'g, Order No. 890-C, 126 FERC ] 61,228, order on 
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
    \5\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 663 
(requiring that generator imbalance provisions account for the 
special circumstances presented by intermittent generators).
---------------------------------------------------------------------------

    3. In this Proposed Rule, the Commission proposes the following 
three reforms: (1) Amend the pro forma OATT to require intra-hourly 
transmission scheduling; (2) amend the pro forma Large Generator 
Interconnection Agreement to incorporate provisions requiring 
interconnection customers whose generating facilities are VERs to 
provide meteorological and operational data to public utility 
transmission providers for the purpose of improved power production 
forecasting; and (3) amend the pro forma OATT to add a generic 
ancillary service rate schedule, Schedule 10--Generator Regulation and 
Frequency Response Service, in which public utility transmission 
providers will offer to provide regulation service for transmission 
customers using transmission service to deliver energy from a generator 
located within a public utility transmission provider's balancing 
authority area. The Commission recognizes that as the number of VERs 
increases, public utility transmission providers and their customers 
will need processes and tools to manage the changing nature of 
generation resources on the transmission grid. As such, the Commission 
believes the reforms proposed herein will address some of the barriers 
to the integration of VERs by remedying operational and other 
challenges that may be causing undue discrimination and increased costs 
ultimately borne by consumers.
    4. Specifically, the Commission preliminarily finds that requiring 
transmission customers to adhere to hourly schedules may be unduly 
discriminatory and result in the inefficient use of transmission and 
generation resources to the detriment of consumers. The Commission also 
preliminarily finds that a lack of VER power production forecasts may 
unnecessarily increase the volume of regulation reserves deployed by a 
public utility transmission provider, resulting in rates that are 
unjust and unreasonable, and that a public utility transmission 
provider currently lacks the means by which to require VERs to provide 
it with basic information on meteorological and operational conditions 
which can be used to develop VER power production forecasts. Finally, 
although the Commission contemplated a case-by-case approach to 
generator regulation service in Order No. 890,\6\ the increased 
interest as evidenced by commenters and the number of Commission 
filings related to this service has led us to consider a generic 
approach to the provision of generator regulation service, such as the 
one proposed here.
---------------------------------------------------------------------------

    \6\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 690.
---------------------------------------------------------------------------

    5. Taken together, these proposed reforms mean: VERs and other 
resources will be able to adjust schedules within the operating hour, 
allowing public utility transmission providers to commit fewer 
generation and non-generation resources to provide reserves; public 
utility transmission providers will have better meteorological and 
operational information from interconnection customers whose generating 
facilities are VERs and will be able to use this information to develop 
power production forecasts for use in operating their systems, thus 
mitigating the volume of regulation reserves they deploy; and public 
utility transmission providers will have a generic schedule from which 
to recover the costs of providing generator regulation service, and 
customers and other market participants will know the cost of such 
service. These proposed reforms are intended to ensure that the 
requirements set forth in the pro forma OATT result in the provision of 
Commission-jurisdictional services at rates that are just and 
reasonable, and not unduly discriminatory or preferential, consistent 
with the Commission's responsibilities under sections 205 and 206 of 
the Federal Power Act (FPA).\7\
---------------------------------------------------------------------------

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

II. Background

    6. In 1996, the Commission issued Order No. 888, which found that 
it was in the economic interest of public utility transmission 
providers to deny transmission service or to offer transmission service 
on a basis that is inferior to that which they provide to 
themselves.\8\ Concluding that unduly discriminatory and 
anticompetitive practices existed in the electric industry and that, 
absent Commission action, such practices would increase as competitive 
pressures in the industry grew, the Commission in Order No. 888 
required all public utility transmission providers that own, control, 
or operate transmission facilities used in interstate commerce to have 
on file an open access, non-discriminatory transmission tariff that 
contains minimum terms and conditions of non-discriminatory service. As 
relevant here, the pro forma OATT contains terms for scheduling 
transmission service and the provision of ancillary services.
---------------------------------------------------------------------------

    \8\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,682 (1996), order 
on reh'g, Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on 
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, 
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub 
nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 
(2002).
---------------------------------------------------------------------------

    7. The Commission later turned its attention to the process by 
which large generators interconnect with the interstate transmission 
system. In Order No. 2003, the Commission concluded

[[Page 75338]]

that there was a pressing need for a single set of procedures and a 
single, uniformly applicable interconnection agreement for large 
generator interconnections.\9\ Accordingly, the Commission adopted 
standard procedures (the Large Generator Interconnection Procedures or 
LGIP) and a standard agreement (the Large Generator Interconnection 
Agreement or LGIA) for the interconnection of generation resources 
greater than 20 MW.\10\ These reforms were designed to minimize 
opportunities for undue discrimination and expedite the development of 
new generation, while protecting reliability and ensuring that rates 
are just and reasonable.\11\
---------------------------------------------------------------------------

    \9\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P 11 
(2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 
31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 
31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. 
] 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. 
Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007).
    \10\ Id.
    \11\ Id.
---------------------------------------------------------------------------

    8. In Order No. 2003-A, the Commission explained that the 
interconnection requirements adopted in Order No. 2003 were based on 
the needs of traditional synchronous generators and that a different 
approach may be appropriate for generators relying on newer 
technology.\12\ The Commission therefore exempted wind resources from 
certain sections of the LGIA and added Appendix G to the LGIA, as a 
placeholder for the inclusion of interconnection standards specific to 
newer technologies.\13\ Subsequently, in Orders Nos. 661 and 661-A, the 
Commission adopted a package of interconnection standards applicable to 
large wind generators for inclusion in Appendix G of the LGIA.\14\
---------------------------------------------------------------------------

    \12\ Order No. 2003-A, FERC Stats. & Regs. ] 31,160 at P 407 
n.85.
    \13\ Id.
    \14\ Interconnection for Wind Energy, Order No. 661, FERC Stats. 
& Regs. ] 31,186 (2005), order on reh'g, Order No. 661-A, FERC 
Stats. & Regs. ] 31,198 (2005).
---------------------------------------------------------------------------

    9. More recently, in recognition of the evolving energy industry 
and in a further effort to remedy the potential for undue 
discrimination, the Commission revised and updated the pro forma OATT 
in Order No. 890.\15\ Among other things, the Commission adopted a set 
of transmission planning principles,\16\ created a new pro forma 
ancillary service schedule designed to address energy imbalances caused 
by generators,\17\ and instituted a new conditional firm transmission 
product.\18\
---------------------------------------------------------------------------

    \15\ Order No. 890, FERC Stats. & Regs. ] 31,241, order on 
reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261, order on 
reh'g, Order No. 890-B, 123 FERC ] 61,299, order on reh'g, Order No. 
890-C, 126 FERC ] 61,228, order on clarification, Order No. 890-D, 
129 FERC ] 61,126.
    \16\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 435-43.
    \17\ Id. P 663-72.
    \18\ Id. P 911-15.
---------------------------------------------------------------------------

    10. As these and other reforms illustrate, the Commission routinely 
evaluates the effectiveness of its regulations and policies in light of 
changing industry conditions. Consistent with this practice, the 
Commission issued the Integrating VERs NOI on January 21, 2010 to 
better understand the challenges associated with the large-scale 
integration of VERs on the interstate transmission system and the 
extent to which existing operational practices may be imposing barriers 
to their integration.\19\ The Commission explained that the changing 
characteristics of the nation's generation portfolio compelled a fresh 
look at existing policies and practices.\20\ Therefore, in the 
Integrating VERs NOI, the Commission sought comments on the following 
subject areas: (1) Power production forecasting, including specific 
forecasting tools and data and reporting requirements; (2) scheduling 
practices, flexibility, and incentives for accurate scheduling of VERs; 
(3) forward market structure and reliability commitment processes; (4) 
balancing authority area coordination and/or consolidation; (5) 
suitability of reserve products and reforms necessary to encourage the 
efficient use of reserve products; (6) capacity market reforms; and (7) 
redispatch and curtailment practices necessary to accommodate VERs in 
real time.\21\
---------------------------------------------------------------------------

    \19\ Integrating VERs NOI, 130 FERC ] 61,053 at P 9.
    \20\ Id.
    \21\ Id. P 12.
---------------------------------------------------------------------------

    11. The response from commenters was significant, with more than 
135 entities submitting comments that responded to some or all of the 
questions posed by the Commission.\22\ A number of commenters, 
especially from the VER industry, argue that there is a clear need for 
the Commission to undertake basic reforms, and they urge the Commission 
to do so.\23\ At the same time, a common theme expressed by a number of 
commenters is that different parts of the country face different 
challenges associated with the integration of VERs.\24\ For example, 
commenters in the Northwest tend to focus on the difficulties posed by 
the deployment of wind resources,\25\ whereas commenters in the 
Southwest tend to focus on the difficulties posed by the deployment of 
solar resources.\26\ Further still, commenters in the South explain 
that in many areas the geography and regional conditions are less 
suitable to the development of significant wind and solar 
resources.\27\ Commenters therefore express a need for flexibility in 
responding to these challenges and urge the Commission to take this 
need into account in crafting any proposed rules.\28\
---------------------------------------------------------------------------

    \22\ See Appendix A.
    \23\ AWEA at 2; Iberdrola at 8-10; NextEra 2-8.
    \24\ Southern at 3; EEI at 2; ISO/RTO Council at 2.
    \25\ See, e.g., NorthWestern at 4-6; Idaho Power at 2-4; Puget 
at 2.
    \26\ See, e.g., NV Energy at 2, 6; Southern California Edison at 
7.
    \27\ See, e.g., Southern at 19.
    \28\ Southern at 4-10; EEI at 2; ColumbiaGrid at 4-5.
---------------------------------------------------------------------------

III. The Need for Reform

    12. The Commission preliminarily finds that the package of reforms 
proposed herein is needed to protect against unjust and unreasonable 
rates, terms, and conditions and undue discrimination in the provision 
of Commission-jurisdictional services. Specifically, the Commission is 
proposing to reform the pro forma OATT to ensure that the services 
provided are not structured in an unduly discriminatory manner, that 
public utility transmission providers have access to needed information 
to facilitate the integration of VERs, and that transmission customers 
have a clear understanding of the determination of and obligations for 
the provision of ancillary services.\29\ The Commission believes that 
this set of proposed reforms represents a reasonable foundation upon 
which public utility transmission providers will be well positioned to 
manage system variability associated with increased numbers of

[[Page 75339]]

VERs. The Commission anticipates that the proposed operational and 
pricing reforms will result in a more efficient utilization of all 
generation, non-generation,\30\ and transmission resources and lay the 
basis for continued development, including the possibility of 
innovative solutions, such as efforts by the Joint Initiative in the 
West.
---------------------------------------------------------------------------

    \29\ As part of this Proposed Rule, the Commission is also 
proposing a minor revision to 18 CFR 35.28. To date, when amending 
its regulations concerning the pro forma OATT, the Commission has 
listed by name Commission rulemaking proceedings promulgating and 
amending the pro forma OATT when explaining the details of a public 
utility transmission provider's obligation to have an OATT on file 
with the Commission (as indicated by, e.g., proposed regulatory text 
included in another recently issued Notice of Proposed Rulemaking: 
Transmission Planning and Cost Allocation by Transmission Owning and 
Operating Public Utilities, 131 FERC ] 61,253 (2010)). This process 
is increasingly cumbersome. Thus as part of this Proposed Rule, the 
Commission proposes to no longer explicitly reference, by name, 
prior Commission rulemaking proceedings promulgating and amending 
the pro forma OATT in its regulations. Likewise, the Proposed Rule 
includes a similar change with respect to a public utility 
transmission provider's obligation to have standard generator 
interconnection procedures and agreements and standard small 
generator interconnection procedures and agreements on file with the 
Commission.
    \30\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 888 
(modifying Schedules 2, 3, 4, 5, 6, and 9 of the pro forma OATT to 
indicate that the ancillary services provided in those rate 
schedules may be provided by generating units as well as other non-
generation resources such as demand response where appropriate).
---------------------------------------------------------------------------

    13. As noted in the Integrating VERs NOI, the composition of the 
electric generation portfolio is changing. VERs are making up an 
increasing percentage of new generating capacity being brought on 
line--in 2009, new wind generating capacity rose to 9,994 MW, or 39 
percent of all newly installed generating capacity, bringing total wind 
generating capacity to more than 35,000 MW.\31\ In addition to this 
existing capacity, another 85 GW of wind generating capacity has been 
proposed to be on line by the end of 2012.\32\ The amount of new solar 
generating capacity also has increased in recent years, adding 351 MW 
in 2008 and 481 MW in 2009, bringing the total solar generating 
capacity to more than 2,000 MW.\33\
---------------------------------------------------------------------------

    \31\ Ryan Wiser & Mark Bolinger, Lawrence Berkeley National 
Laboratory, 2009 Wind Technologies Market Report 3-5 (2010), 
available at https://www1.eere.energy.gov/windandhydro/pdfs/2009_wind_technologies_market_report.pdf.
    \32\ Div. of Energy Market Oversight, Fed. Energy Regulatory 
Comm'n, 2009 State of the Markets Report (2010), available at https://www.ferc.gov/market-oversight/st-mkt-ovr/som-rpt-2009.pdf.
    \33\ Solar Energy Industries Ass'n, US Solar Industry Year in 
Review 2009, at 2, available at https://seia.org/galleries/default-file/2009%20Solar%20Industry%20Year%20in%20Review.pdf.
---------------------------------------------------------------------------

    14. The Commission expects the number of VERs, both in real numbers 
and as a percentage of total generation capacity, to continue to grow. 
Indicators of this anticipated growth are suggested by the significant 
number of public policies, both at the state and federal levels, 
encouraging the development of VERs. In the Integrating VERs NOI, the 
Commission noted that as of December 2009, 30 states and the District 
of Columbia had a renewable portfolio standard.\34\ Moreover, federal 
tax policies that provide incentives to the development of renewable 
generation facilities have been in place for a number of years. For 
example, the federal production tax credit, which has been in effect 
intermittently since the early 1990s, provides an inflation-adjusted 
credit for power produced from VERs and other renewable resources.\35\ 
In February 2009, the American Recovery and Reinvestment Act (ARRA) not 
only extended the production tax credit for a period of three 
additional years,\36\ but also instituted an investment tax credit, 
which allows developers of certain renewable generation facilities to 
take a 30 percent cash grant in lieu of the production tax credit.\37\ 
Other federal policies that provide incentives to renewable generation 
facilities include accelerated depreciation of certain renewable 
generation facilities and loan guarantee programs.
---------------------------------------------------------------------------

    \34\ See Integrating VERs NOI, 130 FERC ] 61,053 at P 2 (citing 
Div. of Energy Market Oversight, Fed. Energy Regulatory Comm'n, 
Renewable Power and Energy Efficiency Market: Renewable Portfolio 
Standards 1 (2009), available at https://www.ferc.gov/market-oversight/othr-mkts/renew/othr-rnw-rps.pdf).
    \35\ 26 U.S.C. 45.
    \36\ American Recovery and Reinvestment Tax Act of 2009, Pub. L. 
111-5, sec. 1101, 123 Stat. 115, 319 (2009).
    \37\ Id. sec. 1102, 123 Stat. 115, 319-20.
---------------------------------------------------------------------------

    15. The Commission has recognized this policy development, not only 
in this proceeding, but also in the Transmission Planning and Cost 
Allocation Proposed Rule, observing that ``state policies to promote 
increased reliance on renewable energy resources, such as the renewable 
portfolio standard measures discussed above, accentuate the need for 
transmission to deliver electricity from location-constrained renewable 
energy resources to load centers.'' \38\ The same observation is true 
for the operational reforms proposed here. Public policies that promote 
renewable resources accentuate the need for reforms to operational 
protocols that unduly discriminate against VERs and/or have the effect 
of maintaining rate structures that are no longer just and reasonable.
---------------------------------------------------------------------------

    \38\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, 131 FERC ] 61,253, at P 36 
(2010) (Transmission Planning and Cost Allocation Proposed Rule).
---------------------------------------------------------------------------

    16. As the number of VERs has increased, the Commission has 
received a variety of proposals that seek variations from the pro forma 
OATT and/or LGIA in order to address system needs resulting from the 
integration of VERs. In recent years, a number of public utility 
transmission providers have proposed to assess various forms of 
ancillary services charges to wind generating resources, while others 
have proposed revised interconnection standards addressing reporting 
requirements and additional ancillary service obligations.\39\ 
Consistent with many of the comments received in response to the 
Integrating VERs NOI, such filings suggest that the pro forma OATT and 
LGIA may need adjustments to address operational issues arising in 
response to the increased integration of VERs in individual balancing 
authority areas.
---------------------------------------------------------------------------

    \39\ See, e.g., NorthWestern Corp., 129 FERC ] 61,116 (2009) 
(NorthWestern), order on reh'g, 131 FERC ] 61,202 (2010); Westar 
Energy Inc., 130 FERC ] 61,215 (2010) (Westar); Cal. Indep. Sys. 
Operator Corp., 131 FERC ] 61,087 (2010); Puget Sound Energy, Inc., 
132 FERC ] 61,128 (2010) (Puget Sound).
---------------------------------------------------------------------------

    17. In light of these filings, comments, and the increasing 
deployment of VERs on the nation's transmission system, the Commission 
has identified reforms that it preliminarily finds would eliminate 
operational procedures that have the de facto effect of imposing an 
undue burden on VERs. The proposed reforms acknowledge that existing 
practices as well as the ancillary services used to manage system 
variability were developed at a time when virtually all generation on 
the system could be scheduled with relative precision and when only 
load exhibited significant degrees of within-hour variation. In 
proposing these reforms, the Commission seeks to ensure that VERs are 
integrated into the transmission system in a coherent and cost-
effective manner, consistent with open access principles.
    18. The Commission is aware that, in many instances, issues 
associated with VER integration are highly technical in nature and can 
vary significantly from one region to the next. The Commission is also 
cognizant of and supports ongoing industry initiatives dedicated to 
crafting regional solutions to the challenges associated with VER 
integration. Such regional efforts include the work being conducted by 
the North American Electric Reliability Corporation (NERC) through the 
Integration of Variable Generation Task Force \40\ and the work of the 
Joint Initiative.\41\ As such, the reforms proposed here do not purport 
to resolve all of the challenges associated with VER integration, nor 
are they intended to undermine progress being made in various regions 
regarding VER integration. The Commission's goal in this proceeding is 
simply to identify those basic reforms that can and should be 
implemented in the near term. The Commission believes that the reforms

[[Page 75340]]

proposed herein can and should be implemented in a way that complements 
ongoing stakeholder proceedings.
---------------------------------------------------------------------------

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

IV. Summary of Proposed Reforms

    19. The Commission is proposing three reforms that, taken together, 
are designed to address issues confronting public utility transmission 
providers and VERs and to allow for the more efficient utilization of 
transmission and generation resources to the benefit of all customers. 
First, the Commission proposes to provide the transmission customer 
with the option of using more frequent transmission scheduling 
intervals within each operating hour, at 15-minute intervals, so that 
they may adjust their transmission schedules to reflect, in advance of 
real-time, more accurate power production forecasts, load profiles, and 
other changing system conditions. At the same time, this proposed 
reform will enable public utility transmission providers and other 
entities to manage the system's variability more effectively and, over 
time, rely less on ancillary services and more on the flexibility of 
generation and non-generation resources.
    20. Second, the Commission proposes to require public utility 
transmission providers to amend their pro forma LGIAs to incorporate 
provisions requiring interconnection customers whose generating 
facilities are VERs to provide certain meteorological and operational 
data to public utility transmission providers to facilitate public 
utility transmission providers' development and deployment of VER power 
production forecasting tools. Under the LGIA provisions proposed here, 
the interconnection customer whose generating facility is a VER would 
only be required to provide such data in the instance where the 
interconnecting public utility transmission provider is developing and/
or deploying VER power production forecasting tools.
    21. Third, the Commission proposes to add a generic ancillary 
service rate schedule to the pro forma OATT through which a public 
utility transmission provider must offer generator regulation service, 
to the extent it is physically feasible to do so from its resources or 
from resources available to it, to transmission customers using 
transmission service to deliver energy from a generator located within 
the transmission provider's balancing authority area. Under this 
proposed rate schedule, a public utility transmission provider will 
have the opportunity to recover reserve service costs associated with 
management of supply-side variability. In Order No. 890, the Commission 
took a case-by-case approach to filings by public utility transmission 
providers seeking to recover the costs of additional regulation 
reserves associated with providing generator imbalance service.\42\ 
This existing policy, however, has led to uncertainty and allows the 
potential for undue discrimination. To prevent this uncertainty and 
potential undue discrimination, we believe it is appropriate now to 
propose a generic generator regulation reserve rate schedule that will 
delineate the rights and obligations of public utility transmission 
providers and customers with respect to the provision of this service.
---------------------------------------------------------------------------

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

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

    \43\ See, e.g., Joint Initiative at 7-12 (explaining ongoing 
efforts in the West to develop a dynamic scheduling system and 
intra-hour transaction accelerator platform to facilitate 
transactions among balancing authorities); ISO/RTO Council at 44 
(indicating that ISOs and RTOs have begun to integrate centralized 
forecasting into reliability commitment processes); NERC, 
Integration of Variable Generation Task Force, 2009-2011 Work Plan 
(2009), available at https://www.nerc.com/docs/pc/ivgtf/IVGTF_Work_%20Plan_111309.pdf (detailing on-going efforts to establish 
mechanisms to calculate the capacity associated with VERs). See also 
Order No. 890, FERC Stats. & Regs. ] 31,241 at P 1626-27 (requiring 
transmission providers to use an OASIS template that will be 
developed by the North American Energy Standards Board to post 
information concerning curtailments, including the circumstances and 
events leading to a firm service curtailment, specific customers and 
services curtailed, and the duration of the curtailment).
---------------------------------------------------------------------------

V. Proposed Reforms

A. Intra-Hourly Scheduling

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

[[Page 75341]]

schedule transmission service on an hourly basis, and adjustments to 
such schedules are permitted during the hour only for emergency 
situations that threaten reliability.\44\ In the Integrating VERs NOI, 
the Commission noted that existing scheduling practices were designed 
at a time when virtually all generation on the system could be 
scheduled with relative precision.\45\ The Commission also acknowledged 
that, with increasing numbers of VERs, system operators appear to be 
relying more on reserves, such as regulation reserves, to balance the 
variation in energy output from VERs.\46\
---------------------------------------------------------------------------

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

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

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

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

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

1. Comments
    28. Most commenters recognize the benefits and support the 
implementation of some form of intra-hour transmission scheduling. AWEA 
states that shorter scheduling intervals will allow generators to 
provide inexpensively much of the flexibility that is currently being 
provided by expensive regulation reserves.\50\ AWEA points out that the 
Avista Wind Integration Study similarly found wind integration costs 
would be reduced by 40-60 percent by moving from hourly to intra-hourly 
dispatch intervals.\51\ Additionally, AWEA asserts that Bonneville has 
publicly stated that wind integration costs on its system would be 
reduced by 80 percent by moving from hourly schedules to intra-hourly 
schedules.\52\ Bonneville states that intra-hour scheduling has the 
potential to help better manage the costs and operational impacts of 
VER generator imbalances.\53\
---------------------------------------------------------------------------

    \50\ AWEA at 38 (citing M. Milligan & B. Kirby, Impact of 
Balancing Area Size, Obligation Sharing, and Ramping Capability on 
Wind Integration, 27-29 (2007), available at https://www.nrel.gov/wind/systemsintegration/pdfs/2007/milligan_wind_integration_impacts.pdf).
    \51\ AWEA at 20 (citing Avista Corp., Wind Integration Study 
(2007), available at https://www.uwig.org/AvistaWindIntegrationStudy.pdf).
    \52\ AWEA at 20 (citing Presentation by Bart McManus, 
Bonneville. Large Wind Integration Challenges and Solutions for 
Operations/System Reliability at slide 26 (Oct. 2008), available at 
https://www.uwig.org/Denver/McManus.pdf) (stating 10 minute schedule 
changes would solve approximately 80% of the issues Bonneville is 
anticipating).
    \53\ Bonneville at 6.
---------------------------------------------------------------------------

    29. WECC explains that shorter scheduling intervals allow system 
operators to manage the integration of VERs more efficiently, because 
they permit the use of forecasts that are closer to the operating time 
frame, and are therefore more accurate.\54\ EEI states that for regions 
with significant amounts of VERs, it appears that shorter intervals 
would allow system operators to manage VER ramp events \55\ and 
variability, provide more accurate scheduling, reduce the reliance on 
regulating reserves and make it easier to meet NERC CPS-2.\56\ NERC 
claims that while additional system flexibility can come from many 
sources, such as the availability of flexible conventional resources 
and non-conventional resources such as storage and demand response 
programs, an additional contributor to greater system flexibility 
includes shorter scheduling intervals, for both within a balancing 
authority area and between balancing authority areas.\57\ Joint 
Initiative states that allowing transmission customers to schedule 
transactions within an operating hour increases operating flexibility 
for VERs and the rest of the system.\58\ NERC claims that the ideal 
scheduling increments to achieve optimum flexibility while still 
meeting relevant reliability requirements may be between five and 
fifteen minutes; however, this depends on system characteristics, the 
type of VERs present on the system, and the level of VER 
penetration.\59\
---------------------------------------------------------------------------

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

    30. AWEA argues that hourly scheduling practices have a much 
greater negative impact on VERs than on traditional dispatchable 
resources and that it is within the Commission's statutory duty to 
address these issues of discrimination.\60\ AWEA notes that shorter 
scheduling intervals will yield significant benefits even on 
transmission systems without wind energy, as there is significant 
intra-hour variability in load, as well as in the output of non-VER 
resources when they experience forced outages or otherwise fail to 
provide their scheduled output.\61\ AWEA also contends that moving to 
shorter dispatch intervals will actually improve power system 
reliability by freeing up additional system flexibility that is 
currently underutilized.\62\ Iberdrola argues that the Commission 
should modify its pro forma OATT to require, at a minimum, intra-hourly 
scheduling of generation, explaining that intra-hour scheduling will 
improve VER scheduling accuracy and reduce VER integration costs.\63\ 
Southern California Edison argues that the Commission should ensure 
that new scheduling tools, such as half-hour scheduling intervals, are 
available, as these could help reduce forecast errors, and in turn, 
result in optimal transmission utilization, market efficiency, and 
system reliability.\64\ Southern California Edison also explains that, 
because it does not expect reliability issues to arise from scheduling 
rule changes, NERC Reliability Standards will require minimal or no 
changes.\65\
---------------------------------------------------------------------------

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

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

[[Page 75342]]

allowed to explore and coordinate its own scheduling practices to suit 
its unique system needs through stakeholder processes. For example, EEI 
states that in light of the variation in market structures and rules 
throughout the country, it is unlikely that any single scheduling 
practice will suit all regions.\66\ EEI argues that the Commission 
should allow each region to explore its own flexible scheduling options 
and provide policy guidance that encourages flexible scheduling 
practices to the maximum extent possible.\67\ Bonneville argues that 
mandating intra-hour scheduling or standardizing national practices is 
premature.\68\ The ISO/RTO Council supports moving toward intra-hour 
scheduling across the inter-ties for purposes of VER integration where 
warranted by system needs.\69\
---------------------------------------------------------------------------

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

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

    \70\ Joint Initiative at 4.
    \71\ Id. at 5-6 (citing sub-hourly scheduling initiatives by the 
following: NV Energy, PacifiCorp, Bonneville, Puget, Portland 
General Electric, Avista Corp., Seattle City Light, Chelan County 
PUD, Grant County PUD, and Tacoma Power).
    \72\ SMUD at 20.
---------------------------------------------------------------------------

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

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

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

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

    35. Smaller public utility transmission providers highlight 
challenges with respect to their size and explain that the 
implementation of intra-hour scheduling may be infeasible for certain 
entities. NRECA indicates that for smaller systems, implementation of 
intra-hour scheduling would be a significant additional burden and 
could require substantial costs in software modification.\82\ NRECA 
explains that while changes to infrastructure required for trading may 
be absorbed by large entities, smaller cooperatives would be affected 
disproportionately because of their inability to spread the costs over 
the large volume of trade.\83\ NRECA claims that in any cost-benefit 
analysis, it is less likely that smaller entities will benefit, even 
over time, especially where they lack a large customer base, which is 
the case for many rural electric cooperatives.\84\ Consequently, NRECA 
contends that intra-hour scheduling is simply infeasible for some of 
its members at this time.\85\
---------------------------------------------------------------------------

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

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

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

---------------------------------------------------------------------------

[[Page 75343]]

2. Commission Discussion
    37. The Commission preliminarily finds that hourly transmission 
scheduling protocols are no longer just and reasonable and may be 
unduly discriminatory as the default scheduling time periods required 
by the pro forma OATT. Specifically, we preliminarily find that 
existing hourly transmission scheduling protocols expose transmission 
customers to excessive or unduly discriminatory generator imbalance 
charges and are insufficient to provide system operators with the 
flexibility to manage their system effectively and efficiently. 
Therefore, the Commission proposes to amend sections 13.8 and 14.6 of 
the pro forma OATT to provide transmission customers the option to 
schedule transmission service on an intra-hour basis, at intervals of 
15 minutes.\89\ The Commission notes that the proposed 15-minute 
interval is consistent with the ideal time increments (i.e., 5 to 15 
minutes) recommended by NERC to achieve greater flexibility while still 
meeting relevant reliability requirements.\90\ Additionally, the 
Commission notes that many commenters claim that shorter scheduling 
intervals may enhance system reliability.\91\ As such, we do not 
believe, as NRECA suggests, that an independent review of NERC 
standards is necessary to making this proposed reform. However, the 
Commission seeks comment on the issue to ensure that there is no 
inconsistency among relevant NERC standards and the proposed intra-hour 
scheduling tariff reform.
---------------------------------------------------------------------------

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

    38. As explained above, hourly transmission scheduling protocols 
were developed at a time when virtually all generation on the system 
could be scheduled with relative precision.\92\ The resulting net 
system variability, i.e., the net variation between the load and 
generator imbalance, was such that hourly scheduling protocols were 
sufficient to maintain system balance. As higher amounts of VERs 
interconnect with the grid, these hourly scheduling protocols make it 
increasingly difficult for public utility transmission providers and 
balancing authorities to maintain system balance.\93\ In order to 
accommodate any increased intra-hour supply-side variability caused by 
increasing numbers of VERs, public utility transmission providers in 
areas without organized real-time energy markets rely on reserve 
services, which are provided under a number of existing ancillary 
service rate schedules.\94\
---------------------------------------------------------------------------

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

    39. The Commission believes that it is unduly discriminatory to 
perpetuate the practice for resources to match hourly transmission 
schedules, especially when the output of a resource (such as a VER) 
fluctuates beyond its reasonable control. Moreover, the Commission 
believes that requiring public utility transmission providers to 
procure ancillary services to manage generating resources' deviations 
across an operating hour is an inefficient and burdensome operating 
protocol with the potential to result in unjust and unreasonable rates. 
Therefore, in order to prevent excessive costs attributable to reserve 
services, an over-reliance on these reserve services in maintaining 
overall system balance, and undue discrimination against VERs, the 
Commission proposes to reform existing transmission scheduling 
practices. Under this proposed reform, all transmission customers will 
have the opportunity to take advantage of the shorter scheduling 
intervals and submit accurate intra-hour schedules, thereby mitigating 
the amount of regulation reserves or other ancillary services public 
utility transmission providers will need to procure.
    40. The Commission expects this proposed reform to benefit many 
types of entities. For example, with shorter scheduling intervals, 
public utility transmission providers should have greater assurance 
that the schedules submitted by transmission customers using VERs are 
accurate. Therefore, these public utility transmission providers will 
be in a better position to anticipate and respond to fluctuations in 
VER energy production. In this way, the public utility transmission 
provider will be able to rely more on planned scheduling and dispatch 
procedures in maintaining overall system balance and rely less on 
reserves. At the same time, transmission customers delivering energy 
from VERs will be in a reasonable position to match their scheduled 
output with actual output, thereby managing their exposure to generator 
imbalance c