[Federal Register Volume 76, Number 120 (Wednesday, June 22, 2011)]
[Proposed Rules]
[Pages 36400-36410]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-15544]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Chapter I

[Docket Nos. RM11-24-000 and AD10-13-000]


Third-Party Provision of Ancillary Services; Accounting and 
Financial Reporting for New Electric Storage Technologies

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice of inquiry.

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SUMMARY: In this Notice of Inquiry (NOI), the Commission seeks comment 
on two sets of separate, but related issues. First, we seek comment on 
ways in which we can facilitate the development of robust competitive 
markets for the provision of ancillary services from all resource 
types. Second, the Commission is interested in issues unique to storage 
devices in light of the role they can play in providing multiple 
services, including ancillary services. As demonstrated by recent cases 
that have come before the Commission, there is growing interest in rate 
flexibility by both purchasers and sellers of ancillary services. A 
variety of resources are poised to provide ancillary services but may 
be frustrated from doing so by certain aspects of the Commission's 
market-based rate policies coupled with a lack of access to the 
information that could help satisfy the requirements of those policies. 
Those with an obligation to purchase ancillary services have raised 
concerns with the availability of those services. In reviewing ways to 
foster a more robust ancillary services market, the Commission 
identified certain issues regarding the use of electric storage as an 
ancillary service resource that warranted consideration. Over time, 
those issues expanded into more global questions as to the role that 
electric storage may play in a competitive market, including how 
electric storage should be compensated for the full range of services 
it provides under the Federal Power Act, and transparency issues 
regarding the Commission's current accounting and reporting 
requirements as applied to electric storage. As such, the Commission 
seeks comment on: Existing restrictions on third-party provision of 
ancillary services, irrespective of the technologies used for such 
provision; and the adequacy of current accounting and reporting 
requirements as they pertain to the oversight of jurisdictional 
entities using electric storage devices.

DATES: Comments are due August 22, 2011.

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

[[Page 36401]]

via phone from Online Support at (202) 502-6652 or toll-free at 1-866-
208-3676.
    Instructions: For detailed instructions on submitting comments and 
additional information on the rulemaking process, see the Comment 
Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT: Rahim Amerkhail (Technical 
Information), Office of Energy Policy and Innovation, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426, 
(202) 502-8266.
    Christopher Handy (Accounting Information), Office of Enforcement, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-6496.
    Eric Winterbauer (Legal Information), Office of General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8329.

SUPPLEMENTARY INFORMATION: 

Notice of Inquiry

June 16, 2011

    1. In this Notice of Inquiry (NOI), the Commission seeks comment on 
two sets of separate, but related issues. First, we seek comment on 
ways in which we can facilitate the development of robust competitive 
markets for the provision of ancillary services from all resource 
types. Second, the Commission is interested in issues unique to storage 
devices in light of the role they can play in providing multiple 
services, including ancillary services. As demonstrated by recent cases 
that have come before the Commission, there is growing interest in rate 
flexibility by both purchasers and sellers of ancillary services. A 
variety of resources are poised to provide ancillary services but may 
be frustrated from doing so by certain aspects of the Commission's 
market-based rate policies coupled with a lack of access to the 
information that could help satisfy the requirements of those policies. 
Those with an obligation to purchase ancillary services have raised 
concerns with the availability of those services. In reviewing ways to 
foster a more robust ancillary services market, the Commission 
identified certain issues regarding the use of electric storage as an 
ancillary service resource that warranted consideration. Over time, 
those issues expanded into more global questions as to the role that 
electric storage may play in a competitive market, including how 
electric storage should be compensated for the full range of services 
it provides under the Federal Power Act, and transparency issues 
regarding the Commission's current accounting and reporting 
requirements as applied to electric storage. As such, the Commission 
seeks comment on: (1) Existing restrictions on third-party provision of 
ancillary services, irrespective of the technologies used for such 
provision; and (2) the adequacy of current accounting and reporting 
requirements as they pertain to the oversight of jurisdictional 
entities using electric storage devices.
    2. More specifically, the Commission is interested in obtaining 
comments on: (1) Whether revising or replacing the restriction set 
forth in Avista Corp. (referred to as the Avista restriction),\1\ which 
prohibits third-party market-based sales of ancillary services to 
transmission providers seeking to meet their ancillary service 
obligations under the Open Access Transmission Tariff (OATT), absent a 
market study showing lack of market power, would help to facilitate the 
provision of ancillary services, and if so, how to balance that goal 
with the need to ensure just and reasonable rates; and (2) Whether 
revising the current accounting and reporting requirements as they 
pertain to regulatory oversight of jurisdictional entities using 
storage technologies is necessary.\2\ Related to the first inquiry, the 
Commission also seeks comment on whether the various cost-based 
compensation methods for frequency regulation that exist in regions 
outside of the current organized markets could be adjusted to address 
the same speed and accuracy issues identified in the recently-issued 
Frequency Regulation Notice of Proposed Rulemaking for organized 
wholesale energy markets.\3\
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    \1\ Avista Corp., 87 FERC ] 61,223 (Avista), order on reh'g, 89 
FERC ] 61,136 (Avista Rehearing Order) (1999).
    \2\ These as well as several other issues were the subject of a 
Commission staff Notice of Request for Comment (Storage RFC) issued 
June 11, 2010. This proceeding focuses primarily on issues 
associated with the pricing of ancillary services and accounting and 
reporting requirements.
    \3\ Frequency Regulation Compensation in the Organized Wholesale 
Power Markets, 76 FR 11177 (Mar. 1, 2011), Notice of Proposed 
Rulemaking, FERC Stats. & Regs. ] 32,672 (2011) (Frequency 
Regulation NOPR).
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I. Background

    3. The Commission has initiated numerous actions over the last 
several decades to foster the development of competitive wholesale 
energy markets by ensuring non-discriminatory access and comparable 
treatment of resources in jurisdictional wholesale markets.\4\ The 
Commission most recently proposed to require all independent system 
operators (ISO) and regional transmission organizations (RTO) to 
compensate resources that provide frequency regulation in a manner that 
reflects the resource's performance in order to remedy undue 
discrimination.\5\
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    \4\ See, e.g., 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 31,781 
(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 (DC Cir. 2000), aff'd sub nom. New York v. FERC, 
535 U.S. 1 (2002); Market-Based Rates for Wholesale Sales of 
Electric Energy, Capacity and Ancillary Services by Public 
Utilities, Order No. 697, FERC Stats. & Regs. ] 31,252, clarified, 
121 FERC ] 61,260 (2007), order on reh'g, Order No. 697-A, FERC 
Stats. & Regs. ] 31,268, clarified, 124 FERC ] 61,055, order on 
reh'g, Order No. 697-B, FERC Stats. & Regs. ] 31,285 (2008), order 
on reh'g, Order No. 697-C, FERC Stats. & Regs. ] 31,291 (2009), 
order on reh'g, Order No. 697-D, FERCStats. & Regs. ] 31,305 (2010); 
Preventing Undue Discrimination and Preference in Transmission 
Service, Order No. 890, FERC Stats. & Regs. ] 31,241, order on 
reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261 (2007), order 
on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g, 
Order No. 890-C, 126 FERC ] 61,228 (2009), order on reh'g, Order No. 
890-D, 129 FERC ] 61,126 (2009); Wholesale Competition in Regions 
with Organized Electric Markets, Order No. 719, FERC Stats. & Regs. 
] 31,281 (2008); order on reh'g, Order No. 719-A, FERC Stats. & 
Regs. ] 31,292 (2009); order on reh'g, Order No. 719-B, 129 FERC ] 
61,252 (2009).
    \5\ See supra note 3.
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    4. As a result of many of these actions, there has been entry not 
only of competitive generation but also new technologies like electric 
storage that can provide many of the same services as generation and 
even transmission. The Commission remains interested in the continued 
development of competitive markets for all services and in this inquiry 
considers the development of a more robust ancillary services market 
and issues unique to storage devices in light of the role they can play 
in providing multiple services, including ancillary services. We also 
note that the role electric storage and other new market entrants play 
in competitive markets is still evolving. With that evolution, the 
Commission must continue to assess the full value those resources 
provide to competitive markets and to ensure just and reasonable rates.
    5. In addition to the Commission's generic initiatives to further 
the development of competitive wholesale markets, the Commission has 
taken action on a case-by-case basis to remove barriers to the entry of 
new technologies. In certain areas of the country where FERC 
jurisdictional tariffs included provisions largely designed for thermal 
resources, and as

[[Page 36402]]

such presented barriers to the participation of other technologies like 
electric storage, the Commission has accepted a variety of proposed 
reforms. For example, Midwest Independent Transmission System Operator 
(Midwest ISO) and New York Independent System Operator, Inc. (NYISO) 
both have tariff provisions for managing the energy level of limited 
energy storage resources (LESRs) providing regulation service.\6\ Also 
under its tariff, NYISO has begun dispatching LESRs first and all other 
resources on a pro-rata basis.\7\ PJM Interconnection, L.L.C. (PJM) has 
tariff provisions excluding most of the energy used for charging 
several types of energy storage devices from its definition of station 
power load.\8\ In 2010, the California Independent System Operator 
Corporation (CAISO) revised the technical requirements for 
participation in its ancillary services market to allow non-generator 
resources to be treated on a comparable basis to generation 
resources.\9\
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    \6\ See Midwest Indep. Trans. Sys. Operator, Inc., 129 FERC ] 
61,303 (2009); New York Indep. Sys. Operator, Inc., 127 FERC ] 
61,135 (2009).
    \7\ See, e.g., New York Indep. Sys. Operator, Inc., 127 FERC ] 
61,135, at P 7 (2009).
    \8\ See PJM Interconnection, L.L.C., 132 FERC ] 61,203 (2010).
    \9\ See California Independent System Operator Corporation, 132 
FERC ] 61,211, at P 26 (2010).
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    6. The Commission has also addressed specific proposals for 
flexibility of the Commission's policies and/or regulations. With 
regard to the Commission's Avista policy, WSPP recently requested 
waiver of the Avista restriction in order to allow market-based rate 
sales of ancillary services under proposed WSPP master sales agreement 
Schedules D and E for those sellers that have market-based rate 
authorization for energy but have not performed market studies for 
ancillary services or proposed any alternative mitigation measure to 
ensure just and reasonable ancillary service rates.\10\
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    \10\ WSPP Inc., 134 FERC ] 61,169 (2011) (WSPP).
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    7. The Commission has also entertained energy storage proposals by 
individual developers, some of which seek treatment only as competitive 
wholesale suppliers, and some of which seek treatment as transmission 
facilities. When faced with various proposals to use energy storage 
technologies for jurisdictional purposes, the Commission has analyzed 
the intended use and capability of storage proposals on a case-by-case 
basis.\11\ Where applicants have sought transmission rate recovery for 
storage assets, the Commission has also reviewed whether the proposal 
would result in: (1) Cross-subsidization of any competitive market 
sales by transmission customers; (2) inappropriate competitive impacts 
if one type of market participant were permitted to receive 
jurisdictional transmission ratebase treatment while other market 
participants are completely at risk in the market; and (3) a level of 
control in the operation of a storage facility by the RTO or ISO that 
could jeopardize its independence from market participants. These 
issues arise when a storage project seeks cost-based transmission rate 
authorization and proposes to participate in competitive wholesale 
energy and ancillary service markets. In contrast, where a storage 
project proposes only to participate in one or more competitive 
wholesale energy and ancillary service markets, these issues do not 
arise because there will be no associated cost-based transmission rate 
for the same storage asset.
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    \11\ See, e.g., Western Grid Development, LLC, 130 FERC ] 
61,056, reh'g denied, 133 FERC ] 61,029 (2010) (Western Grid) and 
Nevada Hydro Co., 122 FERC ] 61,272 (2008) (Nevada Hydro).
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    8. In light of the growing interest in electric storage, Commission 
staff in June 2010 issued the Storage RFC to seek comment on a variety 
of issues including: Alternatives for categorizing and compensating 
storage services, including how best to develop rate policies that 
accommodate the flexibility of storage; whether the Avista restriction, 
which prohibits third-party provision of ancillary services at market-
based rates to transmission providers seeking to meet their own 
ancillary services requirements, can pose an undue barrier to the 
development of storage facilities and other resources capable of 
providing ancillary services; and accounting and financial reporting 
matters as they relate to recovery of costs for electric storage 
technologies, noting that the Commission's accounting and financial 
reporting requirements currently do not contain specific accounting 
\12\ and related reporting requirements \13\ for new storage 
technologies. The Storage RFC noted that storage facilities are 
physically capable of providing a variety of services, including 
transmission service to unbundled transmission customers, enhancing the 
value of generation output sold at wholesale, and providing ancillary 
services.\14\
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    \12\ Uniform System of Accounts Prescribed for Public Utilities 
and Licensees Subject to the Provisions of the Federal Power Act 
(USofA), 18 CFR part 101.
    \13\ Statements and Reports (Schedules), 18 CFR part 141.
    \14\ The Storage RFC also sought comment regarding rate 
treatment alternatives for electric storage technologies depending 
on the intended use or capability of the facility; possible business 
models for storage, including stand-alone storage; and new ancillary 
services products. The Commission will continue to review various 
proposals relevant to these issues on a case-by-case basis and does 
not seek further comment on these matters here.
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    9. As a result of the information developed thus far through these 
various efforts, the Commission's inquiry in this proceeding considers, 
among other things, the application of the Avista policy. We believe 
that markets for ancillary services may not be developing in all 
regions of the country. This may be due in part to the nature of 
ancillary services and the lack of transparent information on the 
capability of individual resources to provide the various services, 
thus hindering sellers'' ability in some regions of the country to 
perform market power studies to demonstrate the lack of market power. 
This coupled with a growing need for ancillary services to support grid 
functions in the face of potential changes in the portfolio of 
generation resources, entry of new technologies seeking to provide the 
services, and the growing interest of sellers and transmission 
providers to have flexibility in meeting ancillary services needs 
prompts this inquiry.
    10. We note that there are numerous issues embedded within these 
broad categories of inquiry and we encourage comment from all 
interested stakeholders. We further note, however, that we will 
continue to address additional matters regarding rate treatment and 
products for electric storage on a case-by-case basis.

II. Discussion

A. Third-Party Provision of Ancillary Services and the Avista 
Restriction

    11. The Commission, in Order No. 888,\15\ contemplated the idea of 
third parties (i.e., parties other than a transmission provider 
supplying ancillary services pursuant to its OATT obligation) providing 
ancillary services on other than a cost-of-service basis if such 
pricing was supported, on a case-by-case basis, by analyses that 
demonstrated that the seller lacks market power. The Commission in

[[Page 36403]]

Order No. 888 and later in Ocean Vista \16\ offered guidance as to what 
should be included in a market power study for ancillary services, 
stating that the guidance was offered for two purposes: (1) To ensure 
that sellers of ancillary services do not exercise market power; and 
(2) to further the goal of promoting competition in ancillary service 
markets.
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    \15\ 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 31,781 (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 
(DC Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \16\ Ocean Vista Power Generation, L.L.C., 82 FERC ] 61,114 
(1998) (Ocean Vista).
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    12. In Avista, the Commission discussed in detail the data problems 
associated with performing a market power study and adopted a policy 
allowing third-party ancillary service providers that could not perform 
a market power study to sell certain ancillary services at market-based 
rates with certain restrictions.\17\ Specifically, the Commission 
allowed a market participant with market-based rate authorization to 
sell ancillary services at market-based rates to transmission customers 
that would otherwise purchase ancillary services from a public utility 
transmission provider. However, the Commission prohibited sales of 
ancillary services at market-based rates by a third-party supplier in 
the following situations: (1) Sales To an RTO or an ISO, which has no 
ability to self-supply ancillary services but instead depends on third 
parties; \18\ (2) to address affiliate abuse concerns, sales to a 
traditional, franchised public utility affiliated with the third-party 
supplier, or sales where the underlying transmission service is on the 
system of the public utility affiliated with the third-party supplier; 
\19\ and (3) sales to a public utility that is purchasing ancillary 
services to satisfy its own OATT requirements to offer ancillary 
services to its own customers.\20\ The Commission further stated that 
it was open to considering requests to make ancillary services sales at 
market-based rates in such circumstances on a case-by-case basis.\21\
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    \17\ The authorization in Avista extended to the following four 
ancillary services: Regulation Service, Energy Imbalance Service, 
Spinning Reserves, and Supplemental Reserves.
    \18\ Subsequently, as the Commission recognized in Order No. 
697, most RTOs and ISOs developed formal ancillary service markets 
and performed associated market power studies, thus rendering this 
component of the Avista policy largely superfluous. See Order No. 
697, FERC Stats. & Regs. ] 31,252 at n.1194 and P 1069.
    \19\ We are not aware of any need to revise this second 
component of the Avista policy.
    \20\ Avista, 87 FERC ] 61,223 at n.12.
    \21\ Id. The Commission has granted waiver of the Avista 
restrictions on a case-by-case basis. See, e.g., NorthWestern Corp. 
and Powerex Corp., 121 FERC ] 61,204 (2007) (granting Powerex 
limited waiver of the prohibition against making sales of ancillary 
services at market-based rates to public utilities that are 
purchasing such services to satisfy their own OATT requirements to 
offer ancillary services to their customers and accepting an 
agreement between NorthWestern and Powerex following a competitive 
solicitation under which Powerex will sell regulating reserve 
services to NorthWestern at market-based rates for a one-year 
period); Powerex Corp., 125 FERC ] 61,179 (2008) (granting Powerex 
limited waiver of the prohibition from making sales of ancillary 
services at market-based rates to public utilities that are 
purchasing such services to satisfy their own OATT requirements to 
offer ancillary services to their customers and conditionally 
accepting an agreement between NorthWestern and Powerex following a 
competitive solicitation under which Powerex will sell regulating 
reserve services to NorthWestern at market-based rates over a two-
year period, subject to extension for an additional year); 
NorthWestern Corp., 125 FERC ] 61,178 (2008) (accepting an agreement 
between NorthWestern and Public Utility District No. 2 of Grant 
County, Washington, following a competitive solicitation under which 
Grant County will sell regulating reserve services to NorthWestern 
at market-based rates over a two-year period, subject to extension).
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    13. In the Avista Rehearing Order, the Commission clarified that 
although Avista prohibits third-party ancillary services suppliers from 
selling to transmission providers in order for transmission providers 
to meet their own ancillary service requirements, a transmission 
provider could purchase from a third-party supplier to permit it to 
offer third-party ancillary services off of its system.\22\ The 
Commission explained:
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    \22\ Avista Rehearing Order, 89 FERC at 61,391.

    We are able to grant blanket authority for flexible pricing only 
because the price charged by the third-party supplier is disciplined 
by the obligation of the transmission provider to offer these 
services under cost-based rates. This discipline could be thwarted 
if the transmission provider could substitute purchases under non-
cost-based rates for its mandatory service obligation.\23\
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    \23\ Id.

The Commission concluded that the protection of the ``backstop of cost-
based ancillary services from the transmission provider will provide an 
appropriate and effective safeguard against potential anti-competitive 
behavior.'' \24\
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    \24\ Avista, 87 FERC ] 61,136 at 61,883.
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    14. Accordingly, absent market studies showing a lack of market 
power, Avista placed a restriction on third-party market-based sales of 
ancillary services to utilities seeking to meet their OATT obligations. 
Under the Commission's Avista policy, third-party sellers that want to 
sell at market-based rates to a transmission provider seeking to meet 
its OATT ancillary service obligations must perform a market power 
study; third party sellers that desire to sell ancillary services at 
market-based rates to entities other than transmission providers may do 
so without restriction.\25\
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    \25\ Although there is no restriction on these sales, the 
transmission provider's OATT rate theoretically serves as a check on 
prices because potential buyers can always resort to OATT service.
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    15. Recently, WSPP requested waiver of the Avista restriction in 
order to allow market-based rate sales of ancillary services under 
proposed WSPP master sales agreement Schedules D and E for those 
sellers that have market-based rate authorization for energy but did 
not perform market studies for ancillary services or proposed any 
alternative mitigation measure to ensure just and reasonable ancillary 
service rates.\26\ In support, WSPP stated that the Avista restrictions 
have foreclosed the development of third-party ancillary services 
markets and relegated transmission providers to provide their own 
reserves through self-supply.\27\ WSPP also argued that there are two 
reasons why market power studies are feasible in RTO/ISO regions but 
not elsewhere: (1) Centralized RTO/ISO markets and related access to 
data ease the way for performance of studies; and (2) RTO/ISOs have 
ready staffs and funds through which studies are feasible.\28\ The 
Commission rejected WSPP's request as it related to sales by a third-
party supplier to satisfy the purchasing transmission provider's own 
OATT requirements to offer ancillary services to its customers. The 
Commission explained that:
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    \26\ WSPP, 134 FERC ] 61,169 at P 5.
    \27\ WSPP, Answer, Docket No. ER10-2295-000, at 4 (Filed 
December 10, 2010).
    \28\ Id. at 5.

    (w)hile the Commission wishes to foster entry into ancillary 
service markets, we also must guard against potential 
anticompetitive behavior by third-party suppliers who may have 
market power. We cannot simply assume that no anticompetitive 
behavior would occur were we to grant WSPP's request.\29\
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    \29\ WSPP, 134 FERC ] 61,169 at P 24.

The Commission noted, however, that it remains open to new approaches 
to selling reserve services at market-based rates and encouraged WSPP 
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to submit a revised proposal that addresses the Commission's concerns.

    16. As indicated both in comments to the Storage RFC and the recent 
WSPP filing that sought waiver of the Avista restrictions,\30\ market 
participants are looking for additional flexibility regarding the 
Avista restrictions, partly because the most significant market for 
ancillary services is likely to be transmission providers seeking to 
meet their OATT ancillary service

[[Page 36404]]

obligations. Furthermore, NorthWestern indicated in a filing before the 
Commission that it was unable to find sellers of ancillary services 
when it issued a request for proposals, noting that only two offers 
were able to satisfy the technical requirements and time commitments 
set forth in the request for proposals from the 70 entities that 
received the request for proposals.\31\ Several commenters in response 
to the Storage RFC also argue that experience has proven this 
restriction to be unnecessary, potentially harmful to both load-serving 
entities and would-be third-party suppliers of ancillary services, and 
a barrier to the use of storage technologies to provide ancillary 
services.\32\
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    \30\ WSPP's request for waiver was rejected by the Commission. 
Id. P 27.
    \31\ See NorthWestern, 121 FERC ] 61,204 at P 6 (2007).
    \32\ See, e.g., AEP August 9, 2010 Comments at 15 and EEI August 
9, 2010 Comments at 9.
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    17. As the Commission explained in WSPP,\33\ the prohibition on 
third-party ancillary service sales to transmission providers seeking 
to meet their own ancillary service requirements was designed to 
address the Commission's concern that the backstop of cost-based 
ancillary services from the transmission provider would not remain an 
effective safeguard against anti-competitive behavior by third-party 
sellers, if the transmission provider's OATT rates were allowed to 
include a pass through of purchases under non-cost-based rates from 
third parties who had not performed a market power study.
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    \33\ WSPP, 134 FERC ] 61,169 at P 26.
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    18. However, we acknowledge the interest in creating a market for 
certain ancillary services and recognize concerns sellers have about 
being unable to conduct formal market power studies. We therefore 
request comment on possible ways of modifying the Avista restriction 
while ensuring just and reasonable rates, including comments on 
possible reforms to the Commission's market power study requirements 
and ideas for alternative mitigation to permit rate flexibility. 
Specifically, we request comment on the following.
1. Market Power Study
    19. Concerns regarding the ability of a seller to perform a market 
power study for ancillary services that were present at the time of 
Avista appear to remain today for sellers in some regions of the 
country. As such:
    a. Is information on individual generating unit frequency 
regulation, spinning and non-spinning reserve capability publicly 
available?
    b. If the Commission retains the requirement of a formal market 
power study as described in Order No. 888 and Ocean Vista for third 
party provision of ancillary services to transmission providers, what 
specific information and tools would be useful to the development of 
these studies?
    c. What are some of the ways/vehicles that the information above 
can be made publicly available, e.g., Commission reporting requirement 
or voluntary posting?
    d. If commercial sensitivity is an issue, is there an appropriate 
time lag for making information available?
    e. While market power analyses have been performed within the 
organized wholesale energy markets, are there alternative market power 
studies, for example that use less granular data, or take other steps 
like appropriate simplifying assumptions, that could be used in other 
regions to establish whether a seller of ancillary services has market 
power?
2. De Minimis Threshold Below Which Market-Based Rates Authorized
    20. In lieu of requiring sellers to submit formal market power 
studies, should the Commission establish a measure of de minimis market 
presence that would justify a grant of market based-rate authority? 
Specifically:
    a. Should the Commission establish a capacity threshold to 
determine whether an entity has market power, so that an entity that 
owns or controls less than a threshold amount of capacity would be 
presumed to lack market power in the market for provision of ancillary 
services? If so, what would be an appropriate level for this threshold?
    b. Alternatively, should the Commission establish a presumption 
that an entity that provides less than a threshold amount of ancillary 
services over a defined period lacks market power in the relevant 
market for such services? If yes, what would be an appropriate level 
for this threshold? Over what time period(s) should the threshold be 
established (e.g., annual, hourly, daily)? Would it be appropriate to 
make new generating units or other resources eligible for this 
exemption based on their maximum potential sales of ancillary services?
    c. Should the threshold be set for individual ancillary services or 
should it be set for multiple ancillary services that often are good 
substitutes (e.g., spinning and supplemental reserves)?
    d. Would it be appropriate to vary the threshold across different 
balancing authority areas and/or different regions?
    e. Should entities that receive authorization to provide ancillary 
services at market-based rates based on a de minimis presence be 
subject to a periodic filing requirement and/or a ``change in status'' 
filing requirement to ensure that they continue to meet the threshold?
3. Alternative Mitigation To Permit Rate Flexibility
    21. In lieu of requiring that sellers desiring to make sales to 
transmission providers submit formal market power studies, are there 
other measures that could be taken to allow such sales and yet ensure 
just and reasonable rates for third-party market-based ancillary 
services? That is, could the Commission replace the Avista restriction 
with some other means of ensuring that the backstop of cost-based 
ancillary services from the transmission provider will continue to 
provide an appropriate and effective safeguard against potential anti-
competitive behavior?
    a. Would ensuring that transmission providers do not automatically 
pass through the price of any non-cost-based third-party purchases that 
exceed their OATT rate permit the backstop of cost-based ancillary 
services from the transmission provider to continue mitigating third-
party market power?
    b. Alternatively, would it be appropriate to waive the current 
third-party sales restriction in cases where the purchasing 
transmission provider voluntarily commits not to pass-through the price 
of non-cost-based third-party purchases that exceed its OATT rates to 
its wholesale and native load retail customers? Would such a commitment 
by the purchasing transmission provider adequately ensure the continued 
value for third-party market power mitigation of the OATT cost-based 
rate backstop, while still permitting third-party sales to transmission 
providers?
    c. As another alternative, in recognition that new entrants'' costs 
may be higher than those reflected in current OATT rates, we seek 
comment on an explicit price-cap for third-party sales to utilities to 
serve their OATT ancillary service obligations based on the purchasing 
utility's Commission-approved OATT rate plus an adder. For example, 
would an OATT-based cost cap set at 105 percent of the purchasing 
utility's existing OATT rate be appropriate given the potentially 
higher costs of new entrants? \34\ Would a cap equal to 105 percent of 
the purchasing transmission provider's OATT rate generally be high 
enough to cover the costs of new entrants and facilitate a

[[Page 36405]]

market for ancillary services? If not, how much of an adder would be 
needed to cover the costs of new entrants? If such a new resource 
margin is used, should the Commission limit its use to sales among non-
affiliated companies? In addition, should a new resource margin be 
disallowed for sales between transmission providers? \35\ If such a new 
resource margin is used, should the Commission limit its use to times 
when the purchasing transmission provider has to rely on the third 
party provider?
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    \34\ A five percent margin might be justified on the basis of 
our delivered price test in market-based rate proceedings, which 
defines who is in the relevant market by looking at generators whose 
delivered costs of power are within five percent of the market 
price.
    \35\ For purposes of this question, our use of the term 
transmission provider includes sales by its wholesale merchant 
function.
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    d. We also seek comment on whether the WSPP Agreement \36\ is an 
adequate vehicle for implementing a cost-based rate cap for ancillary 
service rates. If such a cap were established, should provision of all 
ancillary services made under the WSPP Agreement that remain at or 
below such cost-justified rate caps be considered just and reasonable, 
with no further mitigation measures needed? We seek comment on the 
following issues with respect to setting a cost-cap in the WSPP 
Agreement: How would such a cost cap be determined? Should such a cap 
for ancillary services be subject to the same requirements as the ``up 
to'' cap for power and energy in the current WSPP Agreement? 
Alternatively, could an experimental cap be based on the average 
ancillary service cost of all OATT sellers participating in the WSPP 
Agreement? Would it be sufficient to base an experimental cap on the 
costs of a ``representative sample'' of OATT sellers participating in 
the WSPP Agreement? How would a ``representative sample'' be 
determined? Should the cap include a new resource margin as described 
above? If yes, how would an appropriate adder be determined? Should a 
market monitor be established to oversee provision of ancillary service 
under the WSPP Agreement? Should this proposal be structured as a 
temporary pilot program, as were the original WSPP service schedules 
for market-based sales of energy and capacity?
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    \36\ The WSPP Agreement was initially accepted by the Commission 
on a non-experimental basis in 1991, and provided for flexible 
pricing for coordination sales and transmission services. See 
Western Sys. Power Pool, 55 FERC  61,099, order on reh'g, 
55 FERC ] 61,495 (1991) aff'd in relevant part and remanded in part 
sub nom. Environmental Action and Consumer Federation of America v. 
FERC, 996 F.2d 401, 302 U.S. App. D.C. 135 (DC Cir. 1992), order on 
remand, 66 FERC ] 61,201 (1994). The WSPP Agreement as it exists 
today permits sellers of electric energy to charge either an 
uncapped market-based rate (for public utility sellers, they must 
have obtained separate market-based rate authorization from the 
Commission to do this), or an ``up to'' cost-based ceiling rate. For 
sellers without market-based rate authority, the cost-based rate 
under the WSPP Agreement consists of an individual seller's 
forecasted incremental cost plus an ``up to'' demand charge based on 
the average fixed costs of a subset of the original parties to the 
WSPP Agreement, so long as the seller can justify the use of this 
charge based on its own fixed costs. Otherwise, the seller must file 
a separate stand-alone rate schedule that is cost-justified based on 
the individual seller's own costs. Currently, there are over 300 
parties to the WSPP Agreement located throughout the United States 
and Canada, including private, public and governmental entities, 
financial institutions and aggregators, and wholesale and retail 
customers.
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    e. Competitive solicitations can be one way of assuring just and 
reasonable rates. If transmission providers undertook open and 
transparent competitive solicitations would this help to facilitate the 
provision of ancillary services and ensure just and reasonable rates? 
Could a standardized competitive solicitation process be developed for 
particular regions or markets?
    f. Finally, we seek comments on any other potential methods of 
mitigation, which would ensure that third-party provision of ancillary 
services at market-based rates remain just and reasonable, while 
facilitating the development of a competitive market.
4. Advancing the Goals of the Frequency Regulation NOPR in all Regions
    22. In the Frequency Regulation NOPR, we proposed to require all 
ISOs and RTOs to compensate resources that provide frequency regulation 
in a manner that reflects the resource's performance in order to remedy 
undue discrimination.\37\ In comments in that proceeding, NaturEner 
questioned whether the NOPR proposal can be extended to the areas 
outside of RTOs and ISOs.\38\ As the Frequency Regulation NOPR notes, 
outside of RTOs and ISOs, transmission providers typically procure 
frequency regulation resources as part of their overall mix of 
resources, and seek cost recovery for those resources through a cost-
based rate.\39\ Assuming a third-party purchase is allowed and pass-
through has been permitted as discussed earlier, we seek comment on 
whether transmission providers could compensate the frequency 
regulation resources they procure based on the principles proposed in 
the Frequency Regulation NOPR, and seek to include such costs in their 
Schedule 3 rates. Accordingly, we seek comment on whether the goals of 
the Frequency Regulation NOPR can be extended to regions outside the 
organized wholesale energy markets. Because these regions largely lack 
competitive markets for ancillary services, the Commission seeks 
comments on different potential frameworks under which the speed and 
accuracy of frequency regulation resources might be appropriately 
valued.
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    \37\ Frequency Regulation Compensation in the Organized 
Wholesale Power Markets, FERC Stats. & Regs. ] 36,672 (2011) 
(Frequency Regulation NOPR).
    \38\ See NaturEner, Comments, Docket No. RM11-7-000, at 3-4 
(filed May 2, 2011).
    \39\ See Frequency Regulation NOPR, 134 FERC ] 61,124 at n.8.
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    a. Were we to allow a cost-based cap for frequency regulation 
service in the WSPP Agreement as described above, how could that cap 
reflect an individual resource's performance?
    b. Should we allow transmission customers that self-supply 
frequency regulation service to determine the amount of capacity they 
procure based on the third-party resource's performance capability? For 
instance, if a transmission customer is required to purchase 2 MW of 
frequency regulation service under pro forma OATT Schedule 3, should we 
allow that customer to purchase less capacity if it purchases from a 
resource that responds more quickly and accurately than the resources 
the transmission provider uses to provide service under Schedule 3? If 
so, how should we determine the amount of capacity the transmission 
customer is required to purchase?
    c. Is there any other way to extend the goals of the Frequency 
Regulation NOPR outside of the ISOs and RTOs?

B. Accounting and Reporting Requirements for Energy Storage Resources

    23. The Commission's accounting \40\ and financial reporting 
requirements \41\ for public utilities \42\ are designed to provide 
information about a reporting entity's financial condition and results 
of operation. This information is important in developing and 
monitoring rates, making policy decisions, and informing the Commission 
and the public about the activities of entities that are subject to 
these accounting and reporting requirements.\43\
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    \40\ 18 CFR part 101.
    \41\ 18 CFR part 141.
    \42\ The term ``Public Utility'' means any person who owns or 
operates facilities subject to the jurisdiction of the Commission 
under the Federal Power Act. 18 CFR part 101 (Definition No. 29).
    \43\ Applicants for market-based rate authority that do not sell 
under cost-based rates frequently seek and typically are granted 
waiver of many or all of these requirements.
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    24. Under the Commission's accounting and reporting requirements, 
public utilities must record and classify electric plant assets in the 
prescribed primary plant accounts based on the purpose served or use of 
the asset to

[[Page 36406]]

produce, transmit, or distribute electric energy. In addition, public 
utilities must also record and classify operation and maintenance (O&M) 
expenses related to such plant assets based on the specific activity 
the efforts support. The electric plant assets and related O&M expenses 
must be reported in annual and quarterly FERC Form Nos. 1, 1-F, and 3-Q 
reports \44\ that are maintained in accordance with the Uniform System 
of Accounts (USofA).\45\
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    \44\ FERC Form No. 1, Annual Report for Major Electric 
Utilities, Licensees and Others (Form No. 1), 18 CFR 141.1; FERC 
Form No. 1-F, Annual Report for Nonmajor Public Utilities and 
Licensees (Form No. 1-F), 18 CFR 141.2; and FERC Form No. 3-Q, 
Quarterly Financial Report of Electric Utilities, Licensees, and 
Natural Gas Companies (Form No. 3-Q), 18 CFR 141.400.
    \45\ 18 CFR part 101.
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    25. The roles of conventional production, transmission, and 
distribution resources are well understood and each has established 
method(s) of accounting, reporting, and cost-based rate recovery. 
However, the same is not necessarily true of new energy storage 
resources,\46\ which can operate in ways that resemble production, 
transmission and/or distribution.\47\ Energy storage resources are 
generally capable of providing multiple services with various benefits 
to the grid. Moreover, while committing not to provide other services 
is one method of addressing the Commission's concerns with cross-
subsidization and inappropriate competitive impacts when a storage 
device seeks transmission rate recovery, the Commission remains open to 
alternative proposals to address those concerns. Accordingly, public 
utilities using energy storage resources might seek multiple methods of 
cost recovery for their investments in, and use of, the assets to 
provide various utility services. Consequently, due to the potential to 
use certain storage technologies to provide multiple services and the 
possibility that a public utility could simultaneously recover costs 
under both cost-based and market-based rates, the Commission seeks 
comment on whether current accounting and reporting requirements for 
activities and costs relating to the operations of new electric energy 
storage resources provide sufficient transparency.
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    \46\ Pumped storage hydroelectric facilities are also energy 
storage resources. However, like other conventional production 
assets, the Commission has established methods of accounting, 
reporting and rate recovery associated with operation of pumped 
storage resources. Thus, we do not seek comment on whether the 
current accounting and reporting requirements for pumped storage 
hydroelectric assets or operations should be revised.
    \47\ For example, like a generator, an energy storage resource 
may be able to act as a power marketer, arbitraging differences in 
peak and off-peak energy prices or selling ancillary services; and 
similar to a transmission asset (e.g., a capacitor) an energy 
storage resource could provide voltage support on the grid, or serve 
other purposes that support transmission service.
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    26. In addition, there are questions concerning the concept of 
using a storage device to provide a transmission service and using a 
storage device to ``substitute'' for, or defer, a certain amount of 
transmission service. Transmission service is the movement of electric 
energy over distance. To the extent that storage devices like capacitor 
banks and batteries are used, for example, to provide reactive support 
to help move electric energy over distance, the Commission has found 
that the cost can be considered part of the cost of providing 
transmission service in those circumstances. The storage device in this 
scenario is ``used and useful'' to the provision of transmission 
service, and thus its costs may be included in the rates that 
transmission customers pay. By contrast, the use of storage for 
transmission deferral or substitution is arguably different from the 
provision of transmission service subject to our rate jurisdiction. 
This is because, rather than supporting the movement of electric energy 
over distance, this concept posits the use of storage or other assets 
to provide electric energy at a given point on the system as a 
replacement for a certain amount of transmission service from elsewhere 
to that point on the system. The Commission seeks comment on this 
distinction.
    27. In the Storage RFC, Staff invited comments on, among other 
things, accounting and reporting modifications to the Commission's 
accounting and financial reporting requirements, which might facilitate 
the development and monitoring of rates related to new electric energy 
storage resources for cost-of-service rate purposes.
    28. Numerous comments were received regarding the need for updating 
the USofA and FERC annual reports. Some commenters were supportive of 
revising the Commission's current accounting and reporting requirements 
to accommodate new electric energy storage resources; \48\ other 
commenters indicated that revisions are unnecessary as the current 
requirements sufficiently accommodate energy storage.\49\ However, most 
comments received were general in nature. Therefore, the Commission 
seeks specific details regarding whether and, if so how, to amend the 
current accounting and reporting requirements to specifically account 
for and report energy storage operations and activities.
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    \48\ See, e.g., AEP August 9, 2010 Comments at 7; ITC Companies 
August 9, 2010 Comments at 14; and M-S-R Public Power Agency and the 
City of Santa Clara, California August 9, 2010 Comments at 13.
    \49\ See, e.g., NRECA August 6, 2010 Comments at 13; AES Energy 
Storage, LLC August 9, 2010 Comments at 8; and FirstEnergy August 9, 
2010 Comments at 6.
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Proposed Accounting and Reporting for Comment

    29. The Commission's existing accounting requirements stipulate 
that utility plant costs be classified and accounted for in the 
following functional classifications: Steam Production, Nuclear 
Production, Hydraulic Production, Other Production, Transmission, 
Distribution, Regional Transmission and Market Operation, and 
General.\50\ These plant classifications have associated primary plant 
accounts as well as O&M expense accounts. However, none of the primary 
plant or O&M expense accounts specifically provides for the accounting 
of costs related to new energy storage resources and operations.
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    \50\ In the Form Nos. 1 and 1-F, the Steam, Nuclear, Hydraulic, 
and Other plant functions are grouped as ``Production Plant'' 
functions.
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    30. As such, it may be difficult for owners of these technologies 
to complete their reporting requirements. This in turn would make it 
difficult for regulators to determine costs and establish appropriate 
rates for new energy storage technologies. Therefore, the Commission is 
seeking comments on accounting for the costs of energy storage 
resources and associated O&M expenses.
    31. In addition, as detailed below, some public utilities will need 
to purchase or internally generate power for use in storage operations. 
However, the USofA does not have specific accounts for recording the 
cost of power purchased or generating expenses incurred in storage 
operations. Therefore, we seek comments on the appropriate accounting 
for these items.
    32. Public utilities that receive rate approval to recover cost 
under more than one cost recovery method can potentially earn multiple 
revenue streams from the provision of multiple services using a single 
storage unit or system. This can lead to revenues earned pursuant to 
services provided under a cost-based rate subsidizing the cost of a 
different service that is provided under a market-based rate or vice-
versa. If this occurs, the Commission's rule against cross-
subsidization would be violated and its ability to appropriately 
develop and monitor cost-based rates of energy storage operations would 
be impacted.

[[Page 36407]]

Therefore the Commission seeks comments on accounting for revenues of 
energy storage operations.
    33. Lastly, to address our transparency concerns for Form Nos. 1 
and 1-F as they relate to reporting requirements associated with energy 
storage assets and operations, we seek comments on changes to the forms 
that may be needed to enhance their usefulness regarding the 
development and monitoring of cost-based rates.
1. New and Modified Plant Accounts
    34. As we have indicated, the costs of new energy storage 
technologies are not explicitly provided for in the existing primary 
plant accounts. The Commission seeks comment on how to provide for 
financial transparency of these costs, as well as how to address issues 
that may develop in accounting and reporting for storage assets due to 
the potential to use the assets to provide multiple services.
    35. We believe there may be a number of options to address these 
issues. For example, new plant accounts could be added to the 
production and transmission functions and an existing plant account 
could be revised in the distribution function. The account that could 
be revised in the distribution function is Account 363, Storage Battery 
Equipment.
    36. The current instructions of Account 363 provide for the 
inclusion of the cost of storage battery equipment used for the purpose 
of supplying electricity to meet emergency or peak demands. The 
instructions to Account 363 could be revised to expand the items 
includible in the account to recognize the unique operating 
characteristics of new energy storage technologies which may provide 
services other than supplying electricity to meet emergency or peak 
demands.\51\
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    \51\ For example, as a distribution resource recorded in the 
account the asset could assist with frequency or voltage regulation 
which, at times, may require it to withdraw electricity from the 
grid rather than supply it and for purposes other than to meet 
emergency or peak demands.
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    37. We seek comment on these ideas and any alternatives that 
commenters may propose. Specifically:
    a. Should new accounts for energy storage plant and equipment be 
created and an existing account be revised as discussed in the above 
example, should new accounts be created and no existing accounts used, 
or do the existing primary plant accounts sufficiently provide for 
energy storage plant and equipment? Please elaborate. Also, if 
applicable, provide examples of new accounts and existing accounts, 
including account instructions that could be created or revised to 
account for energy storage resources.
    b. If the Commission were to continue use of existing primary plant 
accounts for energy storage resources, which accounts will provide the 
transparency needed to develop and monitor cost-based rates? Would 
revisions to the instructions of the accounts be required to account 
for energy storage resources? If so, please provide insight into what 
may be required.
    c. Should the cost of new energy storage plant and equipment be 
recorded within existing utility plant functional classifications 
(i.e., transmission, distribution, and production) or should a new 
functional classification be created for energy storage? What are the 
benefits of one approach over the other? If the Commission were to 
create a new classification(s), please comment on the specific plant 
accounts and account instructions that would be created or modified for 
inclusion in the new asset class.
    d. Are there any other accounting issues that relate to accounting 
for energy storage plant and equipment that should be considered? If 
so, provide options to address the issues.
2. Cost of Power Used in Storage Operations
    38. Some public utilities operating storage resources may purchase 
electricity and store it to arbitrage the difference between the sales 
price of on-peak and off-peak electricity. In these instances, public 
utilities will typically purchase and store low cost off-peak 
electricity that they will sell at higher prices during on-peak 
periods. The USofA requires that purchases of power for resale be 
recorded at cost in Account 555, Purchased Power. Thus, this account 
may sufficiently provide for the recording of the cost of electricity 
stored in storage operations that is sold in wholesale electricity 
markets.
    39. Additionally, Account 555 also provides for the recording of 
net settlements for the exchange of electricity or power. Exchange 
transactions may involve exchanges such as off-peak energy for on-peak 
energy or transactions under pooling or interconnection agreements 
wherein there is a balancing of debits and credits for energy or 
capacity. The net settlement amount is generally the difference between 
the cost of power received and the cost of power returned at the 
respective transaction periods over an agreed upon timeframe.
    40. Public utilities engaging in such exchange transactions could 
be required to record the net settlement amount in Account 555 
consistent with the instructions of the account. Also, consistent with 
these instructions, distinct purchases and sales that are not exchange 
transactions would be recorded as separate purchases and sales. In this 
case, purchases made for resale purposes could be recorded in this 
account; however, if the purchase is not made for resale purposes then 
the transaction may need to be reported in a different account.
    41. Electricity used in storage operations will not be purchased 
for resale or through exchange transactions in all instances. For 
example, electricity may be purchased and stored for later use in the 
provision of transmission services or for other jurisdictional or non-
jurisdictional purposes. Moreover, some RTO tariffs may permit the 
energy that storage facilities absorb and return as part of their 
provision of frequency regulation services to be netted such that no 
purchase of energy for resale occurs; only the energy lost in 
conversion is purchased as part of station power load, and that 
purchased power is not resold. Since Account 555 does not specifically 
provide for recording the cost of power purchased and consumed while 
providing this and similar types of energy consuming services the 
account may not be the appropriate account to record the power 
purchases.
    42. In some cases, depending on the operating characteristics of a 
storage resource or the utility services it provides, a public utility 
may be required to sustain a particular state of charge on its storage 
device to provide utility service. For example, if a storage device is 
primarily intended to provide reserves, then it needs to maintain an 
appropriate state of charge to allow it to discharge the reserved power 
when needed. In contrast, if a storage device is primarily intended to 
provide frequency regulation, which it will do through nearly 
continuous and off-setting charge/discharge operations, then it may not 
need to achieve any one particular beginning state of charge in order 
to provide the targeted utility service.
    43. With respect to energy storage devices that must sustain a 
particular state of charge to provide a particular service, the 
conversion and storage process charges the device so that it reaches 
the state of charge or capacity necessary for doing work. To initially 
attain and to sustain a particular state of charge where needed, public 
utilities may internally generate electricity, purchase it in retail or 
wholesale markets, or engage in exchange

[[Page 36408]]

transactions with merchant generators or centrally dispatched power 
pools.
    44. The cost of power purchased to initially attain a specific 
state of charge at the first installation of the storage assets, prior 
to the commencement of utility service, could be considered a base 
charge and accounted for as such by being included in the total cost of 
the asset. Further, public utilities that must purchase or internally 
generate power to sustain a working state of charge could possibly 
account for the cost of purchased power or generation by recording it 
in existing accounts such as Account 555, Purchased Power, Account 501, 
Fuel, or other existing O&M expense accounts, as appropriate. The 
Commission seeks comment on these ideas, as well as alternatives. 
Specifically:
    a. Should power purchased and stored for resale be recorded in 
Account 555? Would revisions to the instructions of the account be 
required to account for the power purchases; if so, please provide 
insight into what may be required. Are there any alternative methods to 
account for these costs?
    b. Should power purchased that will not be sold for resale but will 
instead be consumed during the provision of services such as frequency 
regulation be accounted for in Account 555, or a different existing O&M 
expense account? Please elaborate. Also, should new accounts be created 
or, alternatively, should existing accounts be revised? We welcome 
examples of new or existing accounts and instructions that could be 
created or revised, respectively, to account for power purchased for 
use in storage operations.
    c. We also seek comment on whether power purchased to initially 
attain a state of charge should be accounted for as a base charge and 
included as a component cost of energy storage plant and equipment. Are 
there any alternative methods to account for power purchased to 
initially attain a state of charge?
    d. Should power purchased to sustain a particular state of charge 
be recorded as an expense in Account 555, a different existing O&M 
expense account, or should a new expense account be created? Please 
explain in detail and, if applicable, provide examples of existing and 
new accounts that could be used and related account instructions.
    e. How should the cost of fuel, or other direct costs, incurred to 
internally generate power for use in energy storage operations be 
accounted? What expense accounts should be used to account for the 
costs?
    f. Are there any other accounting issues that should be considered 
that relate to accounting for power purchased or exchanged, and fuel 
and other direct generating costs incurred for energy storage 
operations? If so, provide options to address the issues.
3. Revenues From Providing Energy Storage Services
    45. The USofA currently requires public utilities to record 
revenues derived from electric operations in specific revenue accounts 
based on the relevant revenue generating activity. Revenues derived 
from energy storage operations may involve the same revenue generating 
activities embodied in the existing revenue accounts. For example, 
Account 447, Sales for Resale, provides for the recording of revenues 
from electricity supplied to other electric utilities or public 
authorities for resale purposes. Electricity from storage operations 
can be sold for resale in wholesale markets, which would require the 
resulting revenues to be recorded in Account 447, Sales for Resale. 
Thus, in this and similar instances, it is possible that the existing 
revenue accounts could be used to account for revenues derived from the 
operations of storage assets.
    46. However, because a public utility storage operator can 
potentially recover costs of operating a storage unit under both cost- 
and market-based rate constructs, recording revenues from storage 
operations in existing revenue accounts may not provide sufficient 
transparency of revenues derived from storage operations. As we 
explained above, where a storage device seeks transmission cost-of-
service rates, any revenues from other services it provides may raise 
cross-subsidization issues. Thus, adequate transparency is needed to 
allow the Commission and others to monitor for cross-subsidization in 
this regard.
    47. The Commission seeks comment on how to address this issue as it 
relates to the development and monitoring of cost-based rates. 
Specifically:
    a. Are existing revenue accounts sufficient to capture potential 
revenues associated with storage operations or should new accounts be 
created? If the existing accounts are used, would the instructions to 
the accounts need to be revised? We welcome examples of revisions to 
the account instructions, if any, that may be needed to account for 
revenues from storage operations. Also, if applicable, provide examples 
of new revenue accounts and instructions that could be created.
    b. Would recording revenues from storage operations in one account, 
for example Account 456, Other Electric Revenues, sufficiently address 
revenue transparency issues? How would this accounting impact 
transparency as it relates to the development and monitoring of cost-
based rates? If the Commission were to require revenues derived from 
storage operations to be accounted for in one account, what account 
should be used, why should it be used, and would the instructions of 
the account need to be revised?
    c. Should new revenue accounts be created to record revenues from 
storage operations? Are there examples of accounts and account 
instructions that could be created to record the revenues?
    d. Are there any other accounting issues that should be considered 
that relate to accounting for revenues derived from storage operations? 
If so, provide options to address the issues.
4. Operation and Maintenance Expenses
    48. Different energy storage technologies have different operating 
cost structures. For example, flywheels generally have relatively low 
O&M expenses but higher upfront capital costs compared to batteries, 
which tend to have lower upfront capital costs, but higher O&M 
expenses. These assets also have differing service lives as compared to 
each other and as compared individually to conventional utility assets. 
Furthermore, the service life of a storage asset may be impacted by the 
demands of the particular function or functions that the asset serves. 
For example, a battery storage device used exclusively for frequency 
regulation may have a different service life from one used to shift 
off-peak generation to on-peak periods.
    49. The service life of an asset will typically correlate to the 
rate(s) at which it is depreciated for accounting and rate making 
purposes. It is important to properly capture expenses from the use of 
the assets for cost-of-service rate purposes. The USofA does not 
provide specific accounts to record O&M expenses of energy storage 
operations. Therefore, we seek comments on the accounting requirements 
for O&M expenses.
    a. Are existing O&M expense accounts sufficient to capture costs 
associated with storage operations? Are there any revisions to existing 
accounts or account instructions that would be required to account for 
O&M expenses of storage operations?
    b. Should new O&M expense accounts be created? If so, provide 
examples of new accounts and account instructions that could be created 
to account for O&M expenses of storage operations.

[[Page 36409]]

    c. What accounting issues may arise due to the use of a single 
storage resource to provide services simultaneously under cost- and 
market-based rate recovery constructs? Are there options on how these 
issues may be addressed?
    d. What accounting issues may arise due to the joint ownership of a 
storage facility by separate independent companies that propose to use 
their respective ownership shares of the facility to each provide a 
different jurisdictional service (e.g., wholesale sales of electricity 
and transmission voltage support) under cost- and market-based rate 
recovery mechanisms? Are there options on how these issues may be 
addressed?
    e. Are there other accounting issues that should be considered that 
relate to accounting for O&M expenses associated with storage 
operations? If so, provide options to address the issues.
5. Form Nos. 1 and 1-F
    50. To develop and monitor cost-based rates, the Commission needs 
access to financial data, such as capital and operating costs of 
relevant land, equipment, and labor, as well as nonfinancial data, such 
as volumes sold. For energy storage resources, cost data relating to 
their unique equipment and processes, which are separate from those for 
traditional production plants and transmission and distribution assets, 
are also required. The Form Nos. 1 and 1-F may need to be amended to 
accurately capture these financial and non-financial data. Therefore, 
the Commission seeks comment on whether the Form Nos. 1 and 1-F should 
be revised and, if they should, how to revise them to include 
information on energy storage plant and operations.
    a. Should the Form Nos. 1 and 1-F be amended to provide the 
detailed information required to monitor energy storage operations and 
develop cost-of-service rates?
    b. We welcome examples of new schedules that could be created or 
existing schedules that could be revised to report the costs of energy 
storage plant and equipment and O&M expenses. To provide for 
transparent reporting of costs included in the accounts, it may be 
helpful if such schedules included the following, among other possible 
items: (1) Primary plant accounts and amounts included and reported in 
the general utility plant accounts 101, 103, 106 and 107 for energy 
storage plant by function; and (2) expense accounts and amounts 
included and reported in the general O&M expense accounts 401 and 402 
for storage operations by function.
    c. We also welcome examples of new schedules that could be created 
or existing schedules that could be revised to report the financial and 
non-financial data of storage operations. To provide for transparent 
reporting of this data, it may be helpful if such schedules included 
the following types of financial and non-financial operational data, 
among other possible items: (1) Name and location of energy storage 
plant; (2) Megawatt hours (MWhs) of power purchased, generated, or 
received in exchange transactions for storage, MWhs of power delivered 
to the grid to support production, transmission, or distribution 
operations, MWhs of power lost during conversion, storage and discharge 
of energy by function, and MWhs of power sold for resale; (3) cost of 
power purchased for storage operations, fuel costs for storage 
operations associated with self-generated power, and other costs 
associated with self-generated power; and (4) revenues from energy 
storage operations by service provided and revenues from stored energy 
sold for resale.
    d. Should the same financial and nonfinancial data of energy 
storage assets and operations required to be reported in Form Nos. 1 
and 1-F also be reported to the Commission in the Form No. 3-Q? If not, 
what information on storage assets and operations should be included in 
the Form No. 3-Q?

III. Comment Procedures

    51. The Commission invites interested persons to submit comments on 
the matters, issues and specific questions identified in this notice. 
Comments are due 60 days from publication in the Federal Register. 
Comments must refer to Docket No. RM11-24-000, and must include the 
commenter's name, the organization they represent, if applicable, and 
their address in their comments.
    52. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's Web site at http://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should be filed in native applications or print-to-PDF format 
and not in a scanned format. Commenters filing electronically do not 
need to make a paper filing.
    53. Commenters unable to file comments electronically must mail or 
hand deliver an original and copy of their comments to: Federal Energy 
Regulatory Commission, Secretary of the Commission, 888 First Street 
NE., Washington, DC 20426.
    54. 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.

IV. Document Availability

    55. In addition to publishing the full text of this document in the 
Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington DC 20426.
    56. 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.
    57. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
[email protected].

    By direction of the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

Appendix

List of Commenters in Docket No. AD10-13-000

A123 Systems, Inc.
AES Energy Storage, LLC (AES Energy Storage)
American Electric Power Service Corporation (AEP)
American Public Power Association
Applied Intellectual Capital
Arizona Public Service Company
Beacon Power Corporation
Brookfield Renewable Power Inc. (Brookfield)
California Department of Water Resources State Water Project
California Energy Storage Alliance
California Independent System Operator Corporation
California Public Utilities Commission
Christensen Associates Energy Consulting
City of Santa Clara, California and the M-S-R Public Power Agency
The Coalition to Advance Renewable Energy through Bulk Storage 
(CAREBS)

[[Page 36410]]

Demand Energy
Duke Energy Corporation
Edison Electric Institute (EEI)
Electric Power Supply Association
Electricity Consumers Resource Council
Electricity Storage Association
Energy Cache
Exelon Corporation (Exelon)
FirstEnergy Service Company (FirstEnergy)
General Compression
Grasslands Renewable Energy LLC
ITC Companies
MegaWatt Storage Farms, Inc.
MidAmerican Energy Holdings Company
Modesto Irrigation District
National Alliance for Advanced Technology Batteries (NAATBatt)
National Electrical Manufacturers Association
National Grid USA
National Hydropower Association
National Rural Electric Cooperative Association (NRECA)
New York Transmission Owners
NGK Insulators, Ltd (NGK/TI)
NSTAR Electric Company
Ohio Consumers'' Counsel
Pacific Gas and Electric Company
PJM Interconnection, L.L.C.
Powerex Corp.
Premium Power Corporation
Primus Power Corporation
PSEG Companies
Public Interest Organizations
Puget Sound Energy, Inc.
Riverbank Power Corp.
San Diego Gas & Electric Company (SDG&E)
Six Cities CA
Rodney G. Smith
Southern California Edison Company (SCE)
Southern Company Services, Inc.
Southwest Power Pool, Inc.
Starwood Energy Group Global, LLC.
SunEdison
Symbiotics, LLC
Transmission Agency of Northern California
Viridity Energy, Inc.
Western Grid Development LLC
Xtreme Power Inc. (Xtreme Power)

 [FR Doc. 2011-15544 Filed 6-21-11; 8:45 am]
BILLING CODE 6717-01-P