Integration of Variable Energy Resources, 4316-4323 [2010-1536]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 75, Number 17 (Wednesday, January 27, 2010)]
[Proposed Rules]
[Pages 4316-4323]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2010-1536]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Chapter I

[Docket No. RM10-11-000]


Integration of Variable Energy Resources

Issued January 21, 2010.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of Inquiry.

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SUMMARY: In this Notice of Inquiry, the Federal Energy Regulatory 
Commission (Commission) seeks comment on the extent to which barriers 
may exist that impede the reliable and efficient integration of 
variable energy resources (VERs) into the electric grid, and whether 
reforms are needed to eliminate those barriers. In order to meet the 
challenges posed by the integration of increasing numbers of VERs, 
ensure that jurisdictional rates are just and reasonable, eliminate 
impediments to open access transmission service for all resources, 
facilitate the efficient development of infrastructure, and ensure that 
the reliability of the grid is maintained, the Commission seeks to 
explore whether reforms are necessary to ensure that wholesale 
electricity tariffs are just, reasonable and not unduly discriminatory. 
This Notice will enable the Commission to determine whether wholesale 
electricity tariff reforms are necessary.

DATES: Comments are due March 29, 2010.

ADDRESSES: You may submit comments, identified by docket number by any 
of the following methods:
     Agency Web site: https://ferc.gov. Documents created 
electronically using word processing software should be filed in native 
applications or print-to-PDF format and not in a scanned format.
     Mail/Hand Delivery: Commenters unable to file comments 
electronically must mail or hand deliver an original and 14 copies of 
their comments to: Federal Energy Regulatory Commission, Secretary of 
the Commission, 888 First Street, NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:
Mk Shean (Technical Information), Office of Energy Policy and 
Innovations, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-6792, Mk.Shean@ferc.gov.
Timothy Duggan (Legal Information), Office of General Counsel--Energy 
Markets, Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8326, Timothy.Duggan@ferc.gov.

SUPPLEMENTARY INFORMATION: 
    1. In this Notice of Inquiry, the Federal Energy Regulatory 
Commission (Commission) seeks comment on the extent to which barriers 
exist that may impede the reliable and efficient integration of 
variable energy resources (VERs) \1\ into the electric grid and

[[Page 4317]]

whether reforms are needed to eliminate those barriers. VERs, such as 
resources powered by wind and solar energy, continue to make up an 
increasing percentage of the nation's energy supply portfolio; however, 
they present unique challenges (such as location constraints and 
limited dispatchability) that are not typically presented by 
conventional electricity generating resources. VERs also present 
benefits, such as low marginal energy costs and reduced greenhouse gas 
emissions, which have contributed to the accelerated development of 
these resources. In order to meet these challenges and fully realize 
these benefits of VERs in a reliable and efficient manner, the 
Commission seeks to explore whether reforms of existing policies are 
necessary to ensure that jurisdictional rates are just and reasonable 
and that the terms of jurisdictional service do not unduly discriminate 
against these resources.
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    \1\ For purposes of this proceeding, the term variable energy 
resource (VER) refers to renewable energy resources that are 
characterized by variability in the fuel source that is beyond the 
control of the resource operator. This includes wind and solar 
generation facilities and certain hydroelectric resources.
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I. Background

    2. While the amount of VERs remains relatively small as a 
percentage of total generation, it is rapidly increasing, reaching a 
point where such resources are becoming a significant component of the 
nation's energy supply portfolio. In 2008, new wind generating 
capacity, totaling 8,376 MW, made up 42 percent of all newly installed 
generating capacity.\2\ Moreover, in recent years, a number of state 
renewable portfolio standards and other incentives/mandates have been 
passed to encourage the development of renewable energy resources, in 
response to a growing concern about the environmental impacts and 
sustainability of the Nation's current electricity supply portfolio. As 
of December 2009, 30 states, including the District of Columbia, had a 
renewable portfolio standard.\3\
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    \2\ Div. of Market Oversight, Fed. Energy Regulatory Comm'n, 
2008 State of the Markets Report 19 (2009), available at https://www.ferc.gov/market-oversight/st-mkt-ovr/2008-som-final.pdf.
    \3\ Div. of 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.
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    3. While VERs have many desirable characteristics, including low 
marginal energy costs and reduced greenhouse gas and other pollutant 
emissions, compared to conventional fossil-fueled generation, they also 
present unique challenges as public utilities work to integrate VERs in 
a way that ensures system reliability. For example, because VERs cannot 
control or store their fuel source, they have limited ability to 
control their production of electricity, and the weather-related 
phenomena that drive VER output levels can be difficult to forecast. 
Also, the output from some VERs can be negatively correlated with 
demand, such that a resource's greatest energy output often comes at a 
time of limited energy demand. Changes in the rate of output from VERs 
may also result in substantial ramps,\4\ which can require additional 
resources to allow System Operators \5\ to balance generation and 
demand while maintaining reliability in real time.
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    \4\ A ramp is the rate, expressed in megawatts per minute, that 
a generator changes its output.
    \5\ System Operator refers to the individual at a control 
center--balancing authority, transmission operator, generator 
operator (VERs as well as conventional resources), or reliability 
coordinator--whose responsibility it is to monitor and control the 
electric system in real time.
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    4. In this proceeding, the Commission seeks to explore whether 
existing rules, regulations, tariffs, or industry practices within the 
Commission's jurisdiction may hinder the reliable and efficient 
integration of VERs, resulting in rates that are unjust and 
unreasonable and/or terms of service that unduly discriminate against 
certain types of resources. The Commission seeks comment on how best to 
reform any such rules, regulations, tariffs, or industry practices.
    5. Under sections 205 and 206 of the Federal Power Act, the 
Commission has a responsibility to remedy undue discrimination with 
respect to transmission of electric energy and sales of electric energy 
for resale in interstate commerce and to ensure that rates for these 
services are just and reasonable.\6\ As the electric power industry has 
evolved, the Commission has discharged this responsibility in different 
ways. In Order No. 888, the Commission exercised its authority to 
remedy undue discrimination by requiring all public utilities to 
provide open access transmission service consistent with the terms of a 
pro forma open access transmission tariff (OATT).\7\ The pro forma OATT 
addresses the terms of transmission service, including, among other 
things, the terms for scheduling transmission service, curtailments, 
and the provision of ancillary services. In Order No. 2003, the 
Commission acted to remove barriers in the generator interconnection 
process and adopted standard procedures (the Large Generation 
Interconnection Procedures or LGIP), and a standard agreement (the 
Large Generation Interconnection Agreement or LGIA) for the 
interconnection of generation resources larger than 20 MW.\8\ More 
recently, in a further effort to remedy the potential for undue 
discrimination, the Commission revised and updated the pro forma OATT 
in Order No. 890.\9\
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    \6\ 16 U.S.C. 824d, 824e.
    \7\ 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 (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).
    \8\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (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). Similarly, the 
Commission also adopted standard procedures for the interconnection 
of small generation resources. Standardization of Small Generator 
Interconnection Agreements and Procedures, Order No. 2006, FERC 
Stats. & Regs. ] 31,180, order on reh'g, Order No. 2006-A, FERC 
Stats. & Regs. ] 31,196 (2005), order granting clarification, Order 
No. 2006-B, FERC Stats. & Regs. ] 31,221 (2006).
    \9\ 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, order on 
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
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    6. With limited exceptions,\10\ these and other Commission efforts 
to remedy undue discrimination have not expressly accounted for the 
differences between VERs and more conventional generation resources. In 
large part this is due to the fact that the electric grid was developed 
during a time when electricity was almost exclusively generated from 
centralized, dispatchable resources that were powered by fuel sources 
that could be stored and used as needed. The Commission's policies and 
the concomitant implementation of its responsibility under sections 205 
and 206 were premised on this underlying physical reality of the 
electric grid.
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    \10\ See, e.g., 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) (adopting reforms to the LGIA and 
LGIP to establish standard technical requirements for 
interconnection of wind plants); Order No. 890, FERC Stats. & Regs. 
] 31,241 at P 665 (establishing a standard offer generation 
imbalance service, but exempting intermittent resources from the 
highest penalty band).
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    7. Where relevant, however, the Commission on several occasions has 
taken the operational characteristics of

[[Page 4318]]

VERs into consideration in efforts to ensure just and reasonable rates 
and to remedy undue discrimination. In Order No. 661, the Commission 
required public utilities to revise their LGIAs and LGIPs to 
incorporate standard technical requirements for the interconnection of 
wind resources larger than 20 MW.\11\ In Order No. 890, the Commission 
applied a reduced penalty amount to intermittent resources' imbalances 
that would otherwise be subject to the highest-tier generation 
imbalance penalties, recognizing ``that intermittent generators cannot 
always accurately follow their schedules and that high penalties will 
not lessen the incentive to deviate from their schedules.'' \12\ In 
addition, in Order No. 890 the Commission created conditional firm 
point-to-point transmission service, noting that conditional firm 
service can be particularly beneficial to renewable energy 
resources.\13\ Shortly after the issuance of Order No. 890, the 
Commission accepted a unique cost allocation mechanism for 
interconnection facilities connecting renewable energy resources that 
are location-constrained, recognizing that the difficulties faced by 
these resources are different from those faced by other generation 
developers, and therefore support an appropriate variation of the 
interconnection pricing policy.\14\
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    \11\ Order No. 661, FERC Stats. & Regs. ] 31,186 (adopting, 
among other things, a low voltage ride-through standard, a power 
factor range, dynamic reactive power capability, and supervisory 
control and data acquisition (SCADA) capability).
    \12\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 664-65.
    \13\ Id. P 912.
    \14\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061, at P 
69-70 (2007). See also Southwest Power Pool, Inc., 127 FERC ] 
61,283, at P 29 (2009) (accepting a proposal to allocate network 
upgrade costs differently for wind resources being used to serve 
demand in a different zone than the methodology used for other 
resources).
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    8. Such actions are premised on the notion that targeted revisions 
to Commission policies are sometimes necessary to ensure that 
jurisdictional rates are just and reasonable and to prevent undue 
discrimination against any one type of customer or resource as the 
characteristics of the nation's generation portfolio change.

II. Subject of the Notice of Inquiry

    9. In this proceeding, the Commission seeks to take a fresh look at 
existing policies and practices in light of the changing 
characteristics of the nation's generation portfolio with the aim of 
removing unnecessary barriers to transmission service and wholesale 
markets for VERs (and other technologies that may aid their 
integration) and promoting greater efficiencies that ultimately will 
reduce costs to consumers. While the Commission seeks comment on 
numerous challenges presented by the integration of VERs, this 
proceeding will not address issues related to transmission planning and 
cost allocation, as the Commission is considering those issues in 
another forum.\15\
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    \15\ Transmission Planning Processes Under Order No. 890, Docket 
No. AD09-8-000 (Oct. 8, 2009) (notice of request for comments).
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    10. Our goal is not to adopt rules that favor one type of supply 
source over another. Instead, the Commission's purpose in this 
proceeding is to investigate market and operational reforms necessary 
to achieve two goals: first, to ensure that rates for jurisdictional 
service are just and reasonable, reflecting the implementation of 
practices that increase the efficiency of providing service; and 
second, to prevent VERs from facing undue discrimination. These goals 
are consistent with the requirements of sections 205 and 206 of the 
FPA.
    11. In addition, the Commission must ensure that any reforms are 
consistent with the need to maintain system reliability in accordance 
with Reliability Standards proposed by the North American Electric 
Reliability Corp. (NERC) and approved by the Commission pursuant to 
section 215 of the FPA.\16\ Although the scope of this proceeding is 
directed to market and operational reforms, in certain instances where 
commenters believe existing NERC Reliability Standards should be 
modified or new standards developed in conjunction with the market 
reforms considered herein, they may indicate as much, if directly 
related to this proceeding. In responding to the following questions, 
commenters should indicate how the reforms that they propose ensure the 
reliable operation of the grid, or would impact the reliable operation 
of the grid, as required by the reliability standards.\17\
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    \16\ 16 U.S.C. 824o.
    \17\ See id. at 824o(a)(3). We note that NERC has an ongoing 
stakeholder process to examine how to accommodate high levels of 
variable generation. See North American Elec. Reliability Corp., 
Accommodating High Levels of Variable Generation (2009).
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III. Questions for Response

    12. To ensure that all generation resources are afforded non-
discriminatory access to wholesale markets and the electric power grid 
and that wholesale market prices and the rates for transmission service 
are just and reasonable, the Commission seeks comment on the perceived 
barriers, and suggested solutions to removing those barriers, of 
integrating VERs into the electric grid in a reliable and efficient 
manner. The Commission's preliminary view is that one of the most 
important operational issues affecting the integration costs for VERs 
involves the reserves necessary to address variability in VER output. 
Addressing this issue means examining a number of operational practices 
and processes that affect both the determination of the amount of 
reserves needed as well as the cost of those reserves. The Commission 
seeks comment on the impact of integrating an increasing number of VERs 
in the following subject areas: (1) Data and reporting requirements, 
including the use of accurate forecasting tools; (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.
    13. The Commission does not seek to limit its inquiry and 
encourages all comments regarding the topics broadly discussed herein. 
Commenters are invited to share with the Commission their overall 
thoughts, including technical, commercial, and legal observations, on 
the challenges posed by the increasing number of VERs, operational and 
technical barriers faced by VERs, and the extent to which Commission 
policies can and/or should be revisited in light of the increasing 
number of VERs. Where commenters believe specific revisions to 
Commission rules and/or pro forma OATT provisions are necessary to 
implement their proposed reforms, they are encouraged to cite those 
rules and/or provisions with specificity and suggest revised language 
as appropriate. In this Notice of Inquiry we seek information with 
regard to whether changes to rules or practices as applied to VERs will 
achieve the Commission's goals. However, there may be instances where a 
change to a rule or practice could also assure just and reasonable 
rates and address undue discrimination if applied to other resources. 
Therefore, we ask commenters to address whether any proposed changes to 
the Commission rules or OATT provisions should apply to all resources. 
In

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addition, the Commission seeks responses to the specific questions 
listed below.

A. Data and Forecasting

    14. The scheduling and operational practices of the bulk power 
system are predicated on the ability to predict, with relative 
precision, the output of generation resources and the ability of 
reserve products to accommodate fluctuations in demand and emergency 
conditions. The rapid increase in the development of VERs has presented 
the industry with a variety of challenges related to predicting the 
exact output of VERs at any point in time.
    15. These challenges could become more manageable for System 
Operators through the development and use of state-of-the-art 
meteorological forecasts, which are supplied with data from multiple 
diverse locations. Specifically, the implementation of enhanced 
forecasting tools and procedures could assist in projecting the output 
of VERs with greater accuracy, thereby promoting the efficient 
scheduling of all generation resources to meet expected demand, 
especially during the morning increase and evening decrease in demand. 
Enhanced forecasting could also allow System Operators in all regions 
to anticipate system ramping events more effectively and respond to 
them in an economically efficient manner, thereby ensuring that 
jurisdictional rates are just and reasonable.
    16. To assist in the development of state-of-the-art forecasting 
tools for VERs, the Commission seeks comment on whether and, if so, how 
the Commission should modify existing operational data reporting 
requirements. The Commission also aims to determine what data and what 
level of data-sharing is necessary, coupled with advanced communication 
and metering tools, to ensure that VERs are integrated in a reliable 
and efficient manner, particularly with respect to scheduling, ramping 
needs, and the procurement of reserve services.
    17. To that end, the Commission seeks comment on the following 
questions:
    1. What are the current practices used to forecast generation from 
VERs? Will current practices in forecasting VERs' electricity 
production be adequate as the number of VERs increases? If so, why?
    2. What is necessary to transition from the existing power 
generation forecasting systems for wind and solar generation resources 
to a state-of-the-art forecasting system? What type of data (e.g., 
meteorological, outage, etc.), sampling frequency, and sampling 
location requirements are necessary to develop and integrate state-of-
the-art forecasts, and what technical or market barriers impede such 
development?
    3. What data, forecasting tools and processes do System Operators 
need to more effectively address ramping events and other variations in 
VER output, and to validate enhanced forecasting tools and procedures?
    4. What operational, outage and meteorological data should the 
Commission require VERs to provide to non-VER System Operators? To what 
size resources, in MWs, should any such data requirements apply, and 
what revisions to the pro forma OATT would be necessary to accommodate 
these requirements?
    5. State-of-the-art forecasts may necessitate the sharing of 
meteorological data across regions to assure that the movement of 
weather patterns can be accurately predicted and analyzed. To what 
extent should meteorological data be made publically available to aid 
in the development of state-of-the-art forecasts? Should the Commission 
require public utilities to maintain a meteorological data reporting 
system? If so, should such a system be akin to or in collaboration with 
Open Access Same Time Information System (OASIS) postings? In order to 
retain the confidentiality of commercially sensitive data reported by 
VERs for the purpose of developing state-of-the-art forecasts, what 
limits and/or safeguards should be established to protect operational 
data and generator outage reports?
    6. Should the Commission encourage both decentralized and 
centralized meteorological and VER energy production forecasting? For 
example, should transmission providers have independent forecasting 
obligations as part of their reliability commitment processes similar 
to what is done today for demand forecasting?
    7. To what extent is a lack of data regarding the operational 
status and forecasted output of distributed, or behind-the-meter, VERs 
leading to a need for additional reserves? To what extent would the 
provision of such data reduce the need for System Operators to rely on 
reserves?

B. Scheduling Flexibility and Scheduling Incentives

1. Scheduling Flexibility
    18. Existing scheduling practices were designed at a time when 
virtually all generation on the system could be scheduled with relative 
precision. With increasing numbers of VERs, System Operators appear to 
be relying more on expensive reserves, such as regulation reserves, to 
balance the variation in energy output from VERs. Improvements in 
scheduling procedures may offer the potential for greater efficiency in 
dispatching all energy resources if the degree of variability can be 
reduced, better anticipated, and/or planned for more precisely.
    19. In regions outside of those run by regional transmission 
organizations (RTOs) or independent system operators (ISOs), resources 
typically schedule transmission service on an hourly basis and are only 
allowed to adjust their schedules during the hour for emergency 
situations that threaten reliability.\18\ Because transmission 
schedules for VERs are typically set 20-30 minutes ahead of the hour, 
the forecast of output may be 90 minutes old by the end of the 
operating hour. Additionally, by limiting the ability of resources to 
adjust their schedules during the hour or to submit shorter scheduling 
timeframes, non-RTO/ISO System Operators may not be utilizing the full 
operational flexibility of the resources on their systems to change 
output levels to address the variable output of VERs.
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    \18\ 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. However, section 
13.8 of the pro forma OATT gives the transmission provider the 
discretion to accept schedule changes no later than 20 minutes prior 
to the operating hour.
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    20. In RTOs/ISOs, real-time markets are employed to address 
imbalance energy needs. Real-time markets utilize intra-hour economic 
dispatch of internal resources, which affords RTOs/ISOs the ability to 
respond quickly and economically to fluctuations in VER supply. 
However, RTOs/ISOs often schedule external resources on an hourly 
basis, consistent with non-RTO/ISO scheduling practices.
    21. The Commission questions whether the retention of existing 
transmission scheduling practices as additional VERs come on-line is 
causing rates for reserves (as part of transmission service) to become 
unjust and unreasonable by inhibiting the ability of VERs to establish 
operationally-viable schedules and preventing System Operators from 
utilizing the full flexibility of their systems. Accordingly, the 
Commission seeks to explore whether greater scheduling flexibility, 
such as intra-hour scheduling, could provide benefits to the system and 
facilitate the reliable and efficient use of all resources.
    22. To that end, the Commission seeks comment on the following 
questions:
    1. Would shorter scheduling intervals allow System Operators to 
more

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efficiently manage the ramps of VERs and/or demand? To what extent 
would the availability of intra-hour scheduling decrease the overall 
reliance on regulation reserves to manage the variability of VERs?
    2. What are the benefits and costs of allowing resources and 
transactions to schedule on an intra-hour basis, and what tariff and/or 
technical barriers exist to implementing intra-hour scheduling? Are 
there best practices that could be implemented to facilitate greater 
intra-hour scheduling?
    3. Are there an optimum number of intervals within the hour for 
scheduling? What time increments would be necessary and/or desirable in 
order to achieve optimum flexibility while still meeting the relevant 
reliability requirements?
    4. Identify any reliability issues that may result from changes to 
the scheduling rules. What changes, if any, to NERC Reliability 
Standards would be needed to fully implement additional scheduling 
flexibility while still ensuring reliability?
    5. How would intra-hour scheduling affect the operation of other 
processes such as available transfer capability (ATC), the E-Tag 
system, issuance of dispatch instructions for generation and/or demand 
resources, transmission loading relief procedures, and/or dynamic 
schedules? What costs would be incurred as a result?
    6. If intra-hour scheduling is implemented in non-RTO/ISO regions, 
how would RTO/ISO scheduling practices at interties be affected? Would 
intra-hour scheduling at interties present problems for RTO/ISO 
markets? If so, describe the problems and feasible solutions for intra-
hour scheduling at interties.
2. Scheduling Incentives
    23. Reforms to existing scheduling practices to promote intra-hour 
scheduling could enable VERs to more accurately meet their schedules, 
which in turn should help to ensure that rates for reserves are just 
and reasonable. In order to achieve overall improvements in scheduling 
accuracy, particularly with respect to VERs, it is also important to 
ensure that such resources have the appropriate incentives to meet 
their schedules with real-time output to the extent feasible.
    24. In Order No. 890, the Commission adopted pro forma OATT 
imbalance provisions that implemented a graduated bandwidth approach to 
imbalance penalties that recognized the link between escalating 
deviations and potential reliability impacts on the system.\19\ The 
Commission exempted intermittent resources from the third tier 
deviation band, which required imbalances of greater than 7.5 percent 
of scheduled amounts (or 10 MW) to be settled at 125 percent of the 
incremental cost or 75 percent of the decremental cost of providing the 
imbalance energy.\20\ Instead, intermittent resources with such 
imbalances would only be subject to the second tier imbalance 
penalties, i.e., 110 percent of the incremental or 90 percent of the 
decremental cost.\21\ The Commission is interested in examining the 
experience with this exemption to determine whether it has resulted in 
scheduling practices that may result in an overall rate for 
transmission service that is not just and reasonable.
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    \19\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 663-64.
    \20\ Id. P 664-65.
    \21\ In RTOs/ISOs, because real-time markets are used to address 
imbalance energy needs, VERs are typically exempt from some pro 
forma OATT deviation penalties.
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    25. To that end, the Commission seeks comment on the following 
questions:
    1. Has the exemption from third-tier penalty imbalances worked as a 
targeted exemption that recognizes operational limitations of VERs,\22\ 
or has it encouraged inefficient scheduling behaviors to develop? If 
the latter, what reforms to this exemption would encourage more 
accurate scheduling practices?
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    \22\ For the purposes of this section, the term ``VERs'' refers 
to the same resources that the Commission identified as 
``intermittent'' in Order No. 890. Order No. 890, FERC Stats. & 
Regs. ] 31,241 at P 666.
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    2. Assuming that efficient forecasting and scheduling practices 
help minimize deviations between scheduled and actual energy output of 
VERs, are additional incentives needed to encourage VERs to submit 
schedules that are informed by state-of-the-art forecasting? What would 
be the proper incentives?
    3. Under an RTO/ISO market design, are there sufficient incentives 
to encourage VERs to submit accurate schedules? What costs and/or 
penalties should be assigned to VERs when their real-time output is not 
accurately scheduled on a forward basis? Should VERs be treated the 
same as conventional resources with respect to deviations from their 
production schedules?

C. Day-Ahead Market Participation and Reliability Commitments

1. Day-Ahead Market Participation
    26. The presence of a day-ahead market is a key characteristic of 
most RTOs/ISOs. When resources are scheduled accurately in the day-
ahead market, subsequent out-of-market commitments are minimized and 
market participants can manage their financial exposure more 
effectively. However, VERs appear to participate in the day-ahead 
market on a limited basis, choosing instead to self-schedule the 
majority of their supply in the real-time energy markets (i.e., act as 
a price taker). Because day-ahead schedules are financially binding, 
there can be significant financial risk for VERs participating in the 
day-ahead market and not being able to meet these obligations in the 
real-time market. This may serve as a disincentive for VERs to 
participate in the day-ahead market.
    27. In light of the increasing number of VERs, the Commission is 
interested in receiving comments on whether the lack of day-ahead 
market participation may be resulting in costly out-of-market 
commitments, thereby rendering rates unjust and unreasonable, as well 
as whether the financial risk associated with participating in the day-
ahead market may unduly discriminate against VERs by inhibiting their 
ability to participate in such a market. Such comments should enable 
the Commission to determine whether reforms are necessary to facilitate 
VERs to participate more in the day ahead market rather than primarily 
in the real time market.
    28. To that end, the Commission seeks comment on the following 
questions:
    1. Does the lack of day-ahead market participation by VERs present 
operational challenges or reduce market transparency as the number of 
VERs increases? Will out-of-market commitments increase as the number 
of VERs increases? If so, why?
    2. How can new or existing market design features assure that the 
day-ahead market will accurately represent real-time system conditions 
and that day-ahead and real-time energy prices will converge under the 
scenario of increasing numbers of VERs?
    3. Do current RTO/ISO market designs place undue barriers to 
participation in forward markets by VERs? Could the timing of certain 
RTO/ISO market design elements, such as the day-ahead market, be 
modified in a manner that would facilitate VERs to participate more in 
the day ahead market rather than primarily in the real time market? If 
so, how?
    4. Would the use of more accurate forecasting tools facilitate 
participation of VERs in the day-ahead market rather than primarily in 
the real time market? If so, how?

[[Page 4321]]

    5. Should the financial risk of VERs' participating in the day-
ahead market be different than the risk imposed on other resources in 
that market in recognition of their unique characteristics? Are there 
settlement practices, such as netting deviations, which could be 
employed to address VERs' participating in the day-ahead market? If so, 
what are they?
    6. Will changes to the financial risk of participating in the day-
ahead market encourage VERs to participate in day-ahead markets, and 
will this participation result in day-ahead market schedules that 
accurately reflect real-time market activity?
2. Reliability Commitments
    29. Following the results of the day-ahead market, RTOs/ISOs 
conduct a reliability unit commitment process to ensure that sufficient 
generation will be available in the appropriate places to meet the RTO/
ISO's estimate of the next day's forecasted demand. If the cleared 
resources are insufficient to meet that demand, the RTO/ISO commits 
additional units. Non-RTOs/ISOs conduct a similar assessment to 
evaluate the sufficiency of bilaterally scheduled resources.
    30. Similar to the inefficiency associated with the lack of intra-
hour transmission scheduling, the lack of a more frequent unit 
commitment process may result in unjust and unreasonable rates by 
causing System Operators to make inefficient reliability commitment 
decisions, which may cause unnecessary system uplift costs.
    31. To that end, the Commission seeks comment on the following 
questions:
    1. Would the implementation of a formalized and transparent intra-
day reliability assessment and commitment process prior to each 
operating hour reduce the amount of reserves needed and/or reduce 
system uplift costs? What would be the optimal time (e.g., 4 to 6 hours 
ahead of the operating hour) for such a process?
    2. Would an additional market that coincides with the timing of an 
intra-day reliability commitment process be beneficial in the forward 
scheduling of VERs? If such a market is implemented, would an intra-day 
reliability commitment process be necessary? Should the frequency of 
scheduling intervals resulting from such a market coincide with intra-
hour schedules discussed above?
    3. What role should centralized forecasting of VERs' output play in 
reliability assessment and commitment processes?
D. Balancing Authority Coordination
    32. Smaller balancing authorities may be unable to capture the 
benefits associated with VERs that are spread across a large and/or 
diverse geographical area. Accordingly, the Commission is interested in 
determining whether a limited ability of smaller balancing authorities 
to efficiently integrate VERs may result in rates that are unjust and 
unreasonable. Therefore, the Commission seeks to explore whether 
increased coordination among balancing authorities has the potential to 
enlarge the base of generation and demand available to customers, 
thereby making variability more manageable and ultimately reducing 
overall costs. In this proceeding, the Commission seeks comments on 
ways to increase customer access to energy, capacity, and reserve 
products through the use of pseudo-ties,\23\ dynamic scheduling, and/or 
other tools and agreements.
---------------------------------------------------------------------------

    \23\ Pseudo-ties are defined as telemetered readings or values 
that are used as ``virtual'' tie line flows between balancing 
authorities where no physical tie line exists.
---------------------------------------------------------------------------

    33. To that end, the Commission seeks comment on the following 
questions:
    1. Will smaller balancing authorities, when operated individually, 
have higher VER integration costs than geographically or electrically 
larger balancing authorities? If so, why?
    2. Should the Commission encourage the consolidation of balancing 
authorities? If so, indicate the potential for and impediments to 
consolidation among balancing authorities and the means by which the 
Commission should encourage consolidation.
    3. What tools or arrangements (e.g., dynamic schedules, pseudo-
ties, and virtual balancing authorities) are available and/or could be 
enhanced or created to reduce barriers to greater operational 
coordination among balancing authorities? What role should the 
Commission play in facilitating inter-balancing authority coordination?
    4. What are the costs and benefits, if any, associated with the 
proliferation of small generation-only balancing authorities? How do 
NERC Certification and Reliability Standards encourage or discourage 
the creation of small generation-only balancing authorities?
    5. The Commission is interested in receiving comments on whether 
the integration of VERs with small host balancing authorities may limit 
the benefits derived from geographical diversity and increase 
integration costs. Should the Commission encourage and/or facilitate 
the creation of a VER balancing authority, essentially a large area 
virtual balancing authority primarily designed to accommodate VERs 
across a broad geographic region? What would be the benefits and costs 
of creating such a large area entity?
    6. Would a large area VER balancing authority be capable of 
capturing the reduced variability of VERs located across a broad and 
geographically diverse region? What tariff or technical limitations 
would prevent and/or inhibit the development of a large area VER 
balancing authority?
    7. What reliability impacts may be associated with the creation of 
a large area VER balancing authority?
    8. Should a large area VER balancing authority be limited only to 
VERs? Why or why not?
    9. Should the Commission consider establishing specific policies 
that support the creation of a large area VER balancing authority? If 
so, why?

E. Reserve Products and Ancillary Services

    34. During normal operations, System Operators maintain reserve 
products to ensure that demand and generation are kept in balance.\24\ 
Reserve products are generally defined by the timeframes in which they 
are available. In the moments-to-seconds timeframe, Frequency Response 
services provide an immediate arresting of the frequency decline or 
increase due to any system imbalance. In the seconds-to-minutes 
timeframe, regulation services provide maneuverable capacity (typically 
through automatic generation control), and in the minutes-to-hours time 
frame, following services \25\ allow for the rapid deployment of 
resources to maintain and/or restore system balance.
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    \24\ Contingency Reserves are used to recover from variations 
caused by a system disturbance but not for balancing normal 
variations.
    \25\ In RTO/ISO markets, following services are generally 
provided through real-time energy markets.
---------------------------------------------------------------------------

    35. The Commission seeks to explore whether the variability 
associated with increased VER deployment may result in an over-reliance 
on expensive reserves, such as regulation reserves. The Commission 
seeks to ensure that reserves are being used efficiently such that the 
resulting rates are just, reasonable, and not unduly discriminatory. 
The Commission is also interested in ensuring that requirements for 
VERs to contribute to system reliability are not unduly discriminatory. 
Finally, the Commission seeks to ensure that changes to the rules or 
requirements do not hinder the

[[Page 4322]]

reliable operation of the grid under the reliability standards.\26\
---------------------------------------------------------------------------

    \26\ See 16 U.S.C. 824o(a)(3).
---------------------------------------------------------------------------

    36. To that end, the Commission seeks comment on the following 
questions:
    1. To what extent do existing reserve products provide System 
Operators with the most cost-effective means of maintaining reliability 
during VER ramping events? To what extent would the other reforms 
discussed herein, if implemented, mitigate the need for additional 
reforms to existing reserve products without adversely impacting system 
reliability?
    2. How could System Operators, managing the variability of VER 
resources, more fully utilize forecasting information and knowledge 
about existing system conditions to optimize reserve requirement 
levels?
    3. Would a following or similar reserve product facilitate the 
reduction of costs associated with ensuring that sufficient reserve 
capacity is available to address the uncertainty and variability 
associated with VERs? If so, what are the ideal characteristics of such 
a product?
    4. Existing contingency reserve products were designed to be 
utilized by System Operators to respond to disturbances (i.e., 
contingency events) due to a loss of supply and to assure system 
reliability.\27\ Does or should the definition of a contingency event 
include extreme VER ramping events? If so, would an additional level of 
contingency reserves be needed to achieve the same level of system 
reliability? In responding to this question, please include a proposed 
definition of ``extreme ramping event.''
---------------------------------------------------------------------------

    \27\ Disturbance Control Performance, Standard No. BAL-002-0 
(Apr. 1, 2005).
---------------------------------------------------------------------------

    5. Should a new category of reserves, that would be similar to 
contingency reserves, be developed to maintain reliability during VER 
ramping events in a cost effective manner? If so, what benefit would 
such reserves provide to System Operators and customers?
    6. Could the expanded use of reserve-sharing programs between 
balancing authorities contribute to lowering the costs associated with 
integrating VERs? If so, how?
    7. Should the ancillary services provisions of the pro forma OATT 
be revised or new provisions added to expressly address the added 
reserve capacity necessitated by increased number of VERs? If so, how?
    8. Are there new sources and/or providers for reserve products 
(such as inter-balancing authority pooling arrangements, demand 
response aggregators and/or storage devices) that can be used to 
maintain reliability and lower reserve costs during VER ramping events? 
Based on experience, are there characteristics of these new sources of 
reserves that would positively or negatively impact their ability to 
match the reserve product needs presented by the variability of VERs?
    9. To what extent are VERs capable of providing reserve services? 
Should VERs be expected to provide reserve services? What are the 
tariff and technical barriers that may impede VERs from providing these 
reserve products?
    10. To what extent should all resources, and VERs in particular, be 
required to provide Frequency Response? How would such a requirement be 
implemented?
    11. Should the Commission revisit the reactive power requirements 
set forth in Order No. 661? \28\ What other requirements, if any, 
should apply to VERs to ensure that all resources contribute to grid 
reliability in a manner that is not unduly discriminatory?
---------------------------------------------------------------------------

    \28\ Order No. 661, FERC Stats. & Regs. ] 31,186 at P 50-51.
---------------------------------------------------------------------------

F. Capacity Markets

    37. The procurement of capacity services, either through resource 
adequacy bilateral programs or centralized capacity markets, is 
commonplace in RTO/ISO markets.\29\ Typically, VERs are eligible to 
receive compensation for capacity services in most RTOs/ISOs. However, 
due to their operating characteristics and the capacity rating rules, 
which vary among RTOs/ISOs, VERs are eligible to offer only a portion 
of their nameplate capacity. The price paid for capacity services 
depends in part on the amount of available capacity. Additionally, 
resources that participate in capacity markets typically are required 
to offer capacity in the day-ahead market, which, as discussed above, 
VERs often do not do.
---------------------------------------------------------------------------

    \29\ Centralized capacity markets exist in ISO New England, 
Inc., New York Independent System Operator, Inc., and PJM 
Interconnection LLC. California Independent System Operator Corp. 
and Midwest Independent Transmission System Operator, Inc. rely 
primarily on bilateral resource adequacy programs to procure 
capacity services.
---------------------------------------------------------------------------

    38. The Commission questions whether existing rules governing 
capacity markets may result in rates for capacity services that are not 
just and reasonable. Moreover, to the extent existing rules limit the 
ability of VERs to provide capacity services that they are capable of 
providing, the Commission seeks to explore whether such rules may be 
unduly discriminatory.
    39. To that end, the Commission seeks comment on the following 
questions:
    1. Should the Commission examine whether capacity rating rules as 
applied to VERs are unduly discriminatory and investigate whether 
standard rules may be appropriate?
    2. Do obligations for capacity resources to offer into the day-
ahead market unfairly discriminate against VERs? If so, how?
    3. As more VERs choose to become capacity resources, will existing 
processes for compensating capacity services adequately compensate all 
generating resources that may be needed for reliability services? If 
not, what reforms may be necessary? For instance, should the Commission 
examine formation of forward ancillary services capacity markets?
    4. Should capacity markets incorporate a goal of ensuring 
sufficient generation flexibility to accommodate ramping events in 
addition to the goal of ensuring sufficient generation to meet peak 
demand?

G. Real-Time Adjustments

    40. Redispatch and curtailment protocols vary depending on the 
region of the country and scenario. The Commission is interested in 
receiving comments on whether VERs may be curtailed too frequently in 
response to transmission congestion, minimum generation events,\30\ and 
ramping events, because of a lack of clarity in curtailment protocols. 
Accordingly, the Commission seeks to explore whether redispatch and 
curtailment practices and protocols, especially as they relate to VERs, 
are transparent, non-discriminatory and efficient. The Commission also 
seeks to determine whether redispatch and curtailment protocols may 
result in unnecessary costs, thereby rendering rates unjust and 
unreasonable.
---------------------------------------------------------------------------

    \30\ During a minimum generation event, system demand is at its 
lowest and generation resources tend to operate at the minimum 
feasible output level.
---------------------------------------------------------------------------

    41. To that end, the Commission seeks comment on the following 
questions:
    1. How have redispatch and curtailment practices changed with 
increased numbers of VERs? Are there any shortcomings of current 
redispatch and curtailment practices?
    2. Do existing redispatch and curtailment processes unduly 
discriminate against VERs? If so, how should they be modified?
    3. Some RTOs/ISOs will redispatch VERs based on required economic 
bids. Should all RTOs/ISOs implement similar practices? Why or why not?

[[Page 4323]]

    4. Should transmission loading relief protocols be altered to allow 
reliability coordinators in non-RTO/ISO regions to consider economic 
merit when considering curtailing VERs? If so, how? Similarly, should 
redispatch and curtailment protocols in non-RTOs/ISOs be revised to 
consider economic merit for all resources? If so, how?
    5. Is the increasing number of VERs affecting operational issues 
that arise during minimum generation events? Are there ways to minimize 
curtailments during a minimum generation event? Should conventional 
base-load resources be offered incentives to lower their minimum 
operating levels or even shut down during minimum generation events to 
reflect an economically efficient dispatch of resources? If so, what 
would be the benefits and costs of doing so?
    6. To what extent do VERs have the capability to respond to 
specific dispatch instructions? Are there any advanced technologies 
that could be adopted by VERs to control output to match system needs 
more effectively? Should incentives be put into place for VERs that can 
respond to dispatch instructions? If so, what types of incentives would 
be appropriate?

IV. Comment Procedures

    42. The Commission invites interested persons to submit comments, 
and other information on the matters, issues and specific questions 
identified in this notice.
    43. Comments are due March 29, 2010. Comments must refer to Docket 
No. RM10-11-000, and must include the commenter's name, the 
organization they represent, if applicable, and their address in their 
comments.
    44. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's Web site at https://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    45. Commenters that are not able to file comments electronically 
must send an original and 14 copies of their comments to: Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street, NE., Washington, DC 20426.
    46. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.

V. Document Availability

    47. 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 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    48. 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.
    49. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

    By direction of the Commission. Commissioner Norris voting 
present.
Kimberly D. Bose,
Secretary.
[FR Doc. 2010-1536 Filed 1-26-10; 8:45 am]
BILLING CODE 6717-01-P