[Federal Register Volume 77, Number 131 (Monday, July 9, 2012)]
[Proposed Rules]
[Pages 40413-40458]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-15763]



[[Page 40413]]

Vol. 77

Monday,

No. 131

July 9, 2012

Part II





Department of Energy





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Federal Energy Regulatory Commission





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18 CFR Parts 35, 37, and 101





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

Federal Register / Vol. 77 , No. 131 / Monday, July 9, 2012 / 
Proposed Rules

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 35, 37, and 101

[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, Energy.

ACTION: Notice of Proposed Rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes 
to revise certain aspects of its current market-based rate regulations, 
ancillary services requirements under the pro forma open-access 
transmission tariff (OATT), and accounting and reporting requirements. 
Specifically, the Commission proposes to revise its Avista Corp.\1\ 
policy governing the sale of ancillary services at market-based rates 
to public utility transmission providers and reflect such reforms in 
Parts 35 and 37 of the Commission's regulations. The Commission also 
proposes to require each public utility transmission provider to 
include provisions in its OATT explaining how it will determine 
Regulation and Frequency Response reserve requirements in a manner that 
takes into account the speed and accuracy of resources used. Finally, 
the Commission proposes to revise the accounting and reporting 
requirements under its Uniform System of Accounts for public utilities 
and licensees and its forms, statements, and reports, contained in FERC 
Form No. 1, Annual Report of Major Electric Utilities, Licensees and 
Others, FERC Form No. 1-F, Annual Report for Nonmajor Public Utilities 
and Licensees, and FERC Form No. 3-Q, Quarterly Financial Report of 
Electric Utilities, Licensees, and Natural Gas Companies, to better 
account for and report transactions associated with the use of energy 
storage devices in public utility operations.
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    \1\ See Avista Corp., 87 FERC ] 61,223 (Avista), order on reh'g, 
89 FERC ] 61,136 (1999).

DATES: Comments are due 60 days after publication in the Federal 
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Register.

ADDRESSES: Comments, identified by docket number, may be filed in the 
following ways:
     Electronic Filing through http://www.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: Those unable to file electronically 
may mail or hand-deliver comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    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), Federal Energy Regulatory Commission, Office of Energy 
Policy and Innovation, 888 First Street NE., Washington, DC 20426, 
(202) 502-8266; Christopher Handy (Accounting Information), Federal 
Energy Regulatory Commission, Office of Enforcement, 888 First Street 
NE., Washington, DC 20426, (202) 502-6496; Lina Naik (Legal 
Information), Federal Energy Regulatory Commission, Office of the 
General Counsel, 888 First Street NE., Washington, DC 20426, (202) 502-
8882; Eric Winterbauer (Legal Information), Federal Energy Regulatory 
Commission, Office of the General Counsel, 888 First Street NE., 
Washington, DC 20426, (202) 502-8329.

SUPPLEMENTARY INFORMATION: 

139 FERC ] 61,245

Notice of Proposed Rulemaking

(June 22, 2012)

    1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy 
Regulatory Commission (Commission) seeks comment on a package of 
related proposals developed by the Commission based on comments 
received in response to a Notice of Inquiry (NOI) \2\ issued in this 
proceeding on June 16, 2011. As the Commission noted in the NOI, 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. At the same 
time, transmission customers and sellers alike are seeking greater 
transparency with regard to reserve requirements for ancillary 
services, with a particular focus on Regulation and Frequency Response. 
As the Commission has considered ways to foster transparency and 
competition in ancillary services markets, issues also have arisen 
related to accounting for and reporting of sales from energy storage 
devices that, if left unresolved, could impair the ability of these 
resources to participate in markets for ancillary services and other 
services subject to the Commission's jurisdiction.
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    \2\ Third-Party Provision of Ancillary Services; Accounting and 
Financial Reporting for New Electric Storage Technologies, 135 FERC 
] 61,240 (2011) (NOI).
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    2. The NOI explored these topics by seeking comment on existing 
restrictions on third-party provision of ancillary services, 
irrespective of the technologies used for such provision. The NOI also 
questioned whether the various cost-based compensation methods for 
Regulation and Frequency Response service that exist in regions outside 
of the current organized markets could be adjusted to address the same 
speed and accuracy issues identified in the proceeding that led to the 
issuance of Order No. 755.\3\ Finally, the NOI sought comment on the 
adequacy of current accounting and reporting requirements as they 
pertain to the oversight of the provision of jurisdictional services 
from energy storage devices.
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    \3\ Frequency Regulation Compensation in the Organized Wholesale 
Power Markets, Order No. 755, FERC Stats. & Regs. ] 31,324 (2011), 
reh'g denied, Order No. 755-A, 138 FERC ] 61,123 (2012).
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    3. Based on the comments received in response to the NOI, the 
Commission proposes to revise certain aspects of its market-based rate 
regulations, ancillary services requirements under the pro forma open-
access transmission tariff (OATT), and accounting and reporting 
requirements. Specifically, the Commission proposes to revise its 
Avista Corp. policy governing the sale of ancillary services at market-
based rates to public utility transmission providers and reflect such 
reforms in Parts 35 and 37 of the Commission's regulations.\4\ The 
Commission also proposes to require each public utility transmission 
provider to include provisions in its OATT explaining how it will 
determine Regulation and Frequency Response service reserve 
requirements in a manner that takes into account the speed and accuracy 
of resources used. Finally, the Commission proposes to revise certain 
accounting and reporting requirements under its Uniform System of 
Accounts for public utilities and licensees (USofA) \5\ and its forms, 
statements, and reports, contained in FERC Form No. 1 (Form No. 1), 
Annual Report of Major Electric Utilities, Licensees and Others,\6\ 
FERC Form No.

[[Page 40415]]

1-F (Form No. 1-F), Annual Report for Nonmajor Public Utilities and 
Licensees,\7\ and FERC Form No. 3-Q (Form No. 3-Q), Quarterly Financial 
Report of Electric Utilities, Licensees, and Natural Gas Companies,\8\ 
to better account for and report transactions associated with energy 
storage devices used in public utility operations. The Commission seeks 
comment on these proposed reforms.
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    \4\ See Avista Corp., 87 FERC ] 61,223 (Avista), order on reh'g, 
89 FERC ] 61,136 (1999) (Avista Rehearing Order).
    \5\ Uniform System of Accounts Prescribed for Public Utilities 
and Licensees Subject to the Provisions of the Federal Power Act, 18 
CFR part 101 (2011).
    \6\ 18 CFR 141.1 (2011).
    \7\ 18 CFR 141.2 (2011).
    \8\ 18 CFR 141.400 (2011).
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I. Background

    4. 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.\9\ With 
regard to ancillary services, the Commission in Order No. 888 \10\ 
contemplated that third parties (i.e., parties other than a 
transmission provider supplying ancillary services pursuant to its OATT 
obligation) could provide 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 in the 
relevant product market.\11\ Later, in Ocean Vista Power Generation, 
L.L.C.,\12\ the Commission provided guidance regarding such analyses, 
explaining that as a general matter a study of ancillary services 
markets should address the nature and characteristics of each ancillary 
service, as well as the nature and characteristics of generation 
capable of supplying each service, and that the study should develop 
market shares for each service.
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    \9\ 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 (D.C. 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, FERC Stats. & Regs. ] 31,305 
(2010), aff'd sub nom. Montana Consumer Counsel v. FERC, 659 F.3d 
910 (9th Cir. 2011); 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).
    \10\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,781.
    \11\ Order No. 888 required six Ancillary Services to be 
included in the OATT: (1) Scheduling, System Control and Dispatch; 
(2) Reactive Supply and Voltage Control from Generation Sources; (3) 
Regulation and Frequency Response; (4) Energy Imbalance; (5) 
Operating Reserve--Spinning; and (6) Operating Reserve--
Supplemental. Order No. 890 later added a seventh OATT ancillary 
service: Generator Imbalance. See Order No. 890, FERC Stats. & Regs. 
] 31,241 at P 85.
    \12\ 82 FERC ] 61,114, at 61,406-07 (1998) (Ocean Vista).
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    5. The Commission subsequently acknowledged in Avista \13\ that 
data limitations can impair the ability of sellers to perform a market 
power study for ancillary services consistent with the requirements of 
Ocean Vista. The Commission therefore adopted a policy allowing third-
party ancillary service providers that could not perform a market power 
study to sell certain ancillary services \14\ at market-based rates 
with certain restrictions.\15\ In so doing, the Commission reasoned 
that the backstop of cost-based ancillary services from transmission 
providers, in effect, limits the price at which customers are willing 
to buy ancillary services, thus ensuring that the third party sellers' 
rates would remain just and reasonable even without a showing of lack 
of market power. However, the Commission found that this backstop 
failed to provide adequate mitigation of potential third-party market 
power in three situations: (1) Sales to an RTO or an ISO, which has no 
ability to self-supply ancillary services but instead depends on third 
parties;\16\ (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; 
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.\17\
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    \13\ Avista, 87 FERC at 61,882.
    \14\ These ancillary services included: Regulation and Frequency 
Response, Energy Imbalance, Operating Reserve--Spinning, and 
Operating Reserve--Supplemental. The Commission did not extend this 
Avista policy to Reactive Supply and Voltage Control from Generation 
Sources service, which means that third parties wishing to sell this 
ancillary service at market-based rates would remain subject to the 
pre-Avista market power screen requirement. The Commission also did 
not extend the Avista policy to Scheduling, System Control and 
Dispatch service. However, because only balancing area operators can 
provide this ancillary service, it does not lend itself to 
competitive supply.
    \15\ One of the restrictions imposed in Avista was an obligation 
for sellers to establish an Internet-based Web site for providing 
information about and transacting ancillary services and on-going 
reports to the Commission detailing their activities in the 
ancillary services markets. See Avista, 87 FERC at 61,883. In Order 
No. 697, the Commission concluded that subsequent implementation of 
electric quarterly report (EQR) filing requirements justified 
eliminating these requirements under the Avista policy.
    \16\ Subsequently, as the Commission recognized in Order No. 
697, most RTOs and ISOs developed formal ancillary service markets, 
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.
    \17\ Avista, 87 FERC ] 61,223 at n.12.
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    6. The Commission's focus in this proceeding is on the third 
situation above. The concern in this situation has been that if third 
parties who had not been shown to lack market power were permitted to 
sell to public utilities seeking to meet their OATT ancillary service 
obligations, the public utility's ability to recover such purchase 
costs in OATT rates might lead it to agree to above-market purchases, 
which would then be incorporated into the public utility's OATT 
ancillary service rate and gradually increase that rate. This increase 
in turn would reduce the ability of the cost-based OATT rate to serve 
as an alternative to the third-party market based rate, and thus 
undermine the mitigation measure that the Commission relied upon in 
Avista to enable relaxation of the requirement for a market power 
analysis.\18\ In summary, under existing Commission regulation and 
policy, a third-party supplier may sell certain ancillary services at 
market-based rates without showing a lack of market power except under 
the three circumstances identified above.
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    \18\ See Avista Rehearing Order, 89 FERC at 61,391-92 (stating 
that the Commission is ``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 would be thwarted if the transmission provider could 
substitute purchases under non-cost-based rates for its mandatory 
service obligation.'')
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    7. Over a decade has passed since the Commission first developed 
the Avista restrictions. During this time, potential changes to the 
Avista restrictions have been considered by the Commission on several 
occasions. In the rulemaking proceeding leading to the issuance of 
Order No. 697, the Commission sought comment on whether to modify or 
revise the Avista policy and, if so, how.\19\ The Commission ultimately

[[Page 40416]]

retained its policy of not allowing sales of ancillary services by a 
third-party supplier in the three situations identified above, but 
noted its openness to considering requests for market-based rate 
authorization to make such sales on a case-by-case basis.\20\ Such a 
request was submitted by WSPP in 2011. Based on the facts in that 
instance, the Commission rejected WSPP's request as it related to 
market-based sales by a third-party supplier to satisfy the purchasing 
transmission provider's own OATT requirements to offer ancillary 
services to its customers. However, the Commission noted that it was 
open to new approaches in the evaluation of proposals for sales of 
ancillary services at market-based rates and encouraged parties to 
submit proposals that address the Commission's concerns.\21\
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    \19\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 1052.
    \20\ Id. P 1061.
    \21\ WSPP, Inc., 134 FERC ] 61,169 (2011).
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    8. In its ongoing effort to foster the development of competitive 
markets, including those for ancillary services, the Commission has 
continued to evaluate its Avista policy, in particular the restriction 
on the sale of ancillary services by third-parties to a public utility 
that is purchasing ancillary services to satisfy its own OATT 
requirements to offer ancillary services to its own customers. As the 
Commission considered potential revisions to the Avista policy, the 
Commission also has evaluated the extent to which other policies may 
impair development of ancillary services markets in light of 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 service, and the growing 
interest of sellers and transmission providers to have flexibility in 
meeting ancillary services needs.\22\
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    \22\ See, e.g., Integration of Variable Energy Resources, Order 
No. 755, FERC Stats. & Regs. ] 32,664 (2010); and Demand Response 
Compensation in Organized Wholesale Energy Markets, Order No. 745, 
76 FR 16658 (Mar. 24, 2011), FERC Stats. & Regs. ] 31,322 (2011).
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    9. This evaluation led the Commission to issue an NOI in this 
proceeding to seek comment on whether revising this aspect of the 
Avista restriction would be appropriate, either by implementing 
alternative methods of proving a lack of market power or alternative 
methods of mitigating any potential market power. The NOI also sought 
comment on cost-based compensation methods for Regulation and Frequency 
Response service, as well as accounting and reporting requirements as 
they pertain to oversight of the provision of jurisdictional services 
from energy storage devices.
    10. Based on the comments received, the Commission includes in this 
NOPR a package of proposals to facilitate the development of 
competitive markets for ancillary services, increase transparency for 
Regulation and Frequency Response reserve requirements, and better 
account for and report transactions associated with energy storage 
devices used in public utility operations. The Commission describes 
each of these proposals in detail below.

II. Discussion

A. The Avista Policy

    11. As noted above, the Commission's Avista policy authorizes the 
sale of certain ancillary services at market-based rates without 
showing a lack of market power except under specified circumstances. As 
relevant here, a third-party may not sell ancillary services at market-
based rates to a public utility that is purchasing ancillary services 
to satisfy its own open access transmission tariff requirements to 
offer ancillary services to its own customers. In order to overcome 
this restriction, a potential seller must provide a market power study 
demonstrating a lack of market power for the particular ancillary 
service in the particular geographic market. However, commenters in 
response to the NOI note that certain information needed to perform 
such a market power study is not currently available, effectively 
precluding them from the opportunity to make such a showing.\23\ 
Whether due to this or other limitations, the effect of the Avista 
policy is to categorically prohibit sales of ancillary services to 
public utility transmission providers outside of the RTO and ISO 
markets.\24\
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    \23\ WSPP Comments at 7-10, ENBALA Comments at 2-3, California 
Storage Alliance Comments at 5-6, and ESA Comments at 8.
    \24\ As noted above, most RTOs and ISOs have developed formal 
ancillary service markets, allowing for the sale of ancillary 
services at market-based rates in those regions.
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    12. Some commenters suggest that the current analyses used to 
evaluate a seller's ability to exercise horizontal market power in the 
sale of energy and capacity remain sufficient to address market power 
in ancillary services as well.\25\ Other commenters contend that 
alternative mitigation measures would be appropriate for sellers unable 
to perform a market power analysis, such as the use of price caps based 
on the purchasing utility's cost-based OATT ancillary services rates or 
the use of competitive solicitations.\26\ The Commission believes that 
these suggestions may have merit and has developed potential reforms to 
the Avista policy to provide greater flexibility to sellers while 
protecting buyers from the exercise of market power that could lead to 
unjust and unreasonable or unduly discriminatory or preferential rates. 
These proposals are discussed further below.
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    \25\ PPL Companies Comments at 3, EPSA Comments at 5-6, and 
Portland General Comments at 3-4, Shell Energy Comments at 13-16, 
Powerex Comments at 38-40, and WSPP Comments at 11-12. While several 
commenters also support the idea of developing less challenging 
analyses for measuring ancillary service market power, none provides 
any concrete proposals. See, e.g., California PUC Comments at 5.
    \26\ See, e.g., Southern California Edison Comments at 5-6 and 
WSPP Comments at 16.
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1. Use of Market Power Analyses
    13. The Commission analyzes horizontal market power \27\ for sales 
of energy and capacity using two indicative screens, the wholesale 
market share screen and the pivotal supplier screen, to identify 
sellers that raise no horizontal market power concerns and can 
otherwise be considered for market-based rate authority.\28\ The 
wholesale market share screen measures whether a seller has a dominant 
position in the relevant geographic market in terms of the number of 
megawatts of uncommitted capacity owned or controlled by the seller, as 
compared to the uncommitted capacity of the entire market.\29\ A seller 
whose share of the relevant market is less than 20 percent during all 
seasons passes the wholesale market share screen.\30\ The pivotal 
supplier screen evaluates the seller's potential to exercise horizontal 
market power based on the seller's uncommitted capacity at the time of 
annual peak demand in the relevant market.\31\ A seller satisfies the 
pivotal supplier screen if its uncommitted capacity is less than the 
net uncommitted supply in the relevant market.\32\
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    \27\ 18 CFR 35.37(b) (2011).
    \28\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 13, 62. 
See also 18 CFR Sec.  35.37(b), (c)(1) (2011).
    \29\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 43.
    \30\ Id. PP 43-44, 80, 89.
    \31\ 18 CFR 35.37(c)(1) (2011).
    \32\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 42.
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    14. Passing both the wholesale market share screen and the pivotal 
supplier screen creates a rebuttable presumption that the seller does 
not possess horizontal market power; failing either screen creates a 
rebuttable presumption that the seller possesses horizontal market 
power.\33\ A seller that fails one

[[Page 40417]]

of the screens may present evidence, such as a delivered price test 
(DPT), to rebut the presumption of horizontal market power.\34\ In the 
alternative, a seller may accept the presumption of horizontal market 
power and adopt some form of cost-based mitigation.\35\
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    \33\ 18 CFR 35.37(c)(1) (2011).
    \34\ 18 CFR 35.37(c)(2) (2011). For purposes of rebutting the 
presumption of horizontal market power, sellers may use the results 
of the DPT to perform pivotal supplier and market share analyses and 
market concentration analyses using the Herfindahl-Hirschman Index 
(HHI). The HHI is a widely accepted measure of market concentration, 
calculated by squaring the market share of each firm competing in 
the market and summing the results. The Commission has stated that a 
showing of an HHI less than 2,500 in the relevant market for all 
season/load periods for sellers that have also shown that they are 
not pivotal and do not possess a market share of 20 percent or 
greater in any of the season/load periods would constitute a showing 
of a lack of horizontal market power, absent compelling contrary 
evidence from intervenors. Order No. 697, FERC Stats. & Regs. ] 
31,252 at P 111.
    \35\ 18 CFR 35.37(c)(3) (2011).
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    15. Three of the key components of the analysis of horizontal 
market power are the definition of products, the determination of 
appropriate geographic scope of the relevant market for each product, 
and the identification of the uncommitted generation supply within the 
relevant geographic market. In Order No. 697, the Commission adopted a 
default relevant geographic market for sales of energy and 
capacity.\36\ In particular, the Commission will generally use a 
seller's balancing authority area plus first-tier markets, or the RTO/
ISO market as applicable, as the default relevant geographic market. 
However, where the Commission has made a specific finding that there is 
a submarket within an RTO, that submarket becomes the default relevant 
geographic market for sellers located within the submarket for purposes 
of the market-based rate analysis. The Commission also provided 
guidance as to the factors the Commission will consider in evaluating 
whether, in a particular case, to adopt an alternative larger or 
smaller geographic market instead of relying on the default geographic 
market. A necessary condition that must be satisfied to justify an 
alternative market is a demonstration regarding whether there are 
frequently binding transmission constraints during historical peak 
seasons examined in the screens and at other competitive significant 
times that prevent competing supply from reaching customers within the 
proposed alternative geographic market.\37\
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    \36\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 15.
    \37\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 268.
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    16. For sales of energy and capacity, the product definitions are 
well understood, the relevant geographic market is generally the 
default market described above, and the uncommitted generation supply 
is generally identified as all such supply located within the seller's 
balancing authority area plus potential uncommitted imports as 
determined largely by available transmission capacity in the form of 
simultaneous import limits.\38\ In contrast, defining the product, 
determining the relevant geographic market, and identifying uncommitted 
competing resources can be more complex for ancillary services. To date 
the Commission has not received an acceptable market power analysis for 
the sale of ancillary services at market-based rates outside of RTO/ISO 
markets. As noted above, certain commenters in response to the NOI 
contend that the information necessary to perform a market power 
analysis outside of RTO/ISO markets is not currently available.\39\ 
Certain other commenters argue that the current analyses used to 
evaluate a seller's ability to exercise market power in the sale of 
energy and capacity are sufficient to address market power in ancillary 
services as well.\40\
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    \38\ Studies of Simultaneous Transmission Import Limits (SIL) 
quantify a study area's simultaneous import capability from its 
aggregated first-tier area. SIL studies are used as a basis for 
calculating import capability to serve load in the relevant 
geographic market when performing market power analyses.
    \39\ WSPP Comments at 7-10; ENBALA Comments at 2-3; California 
Storage Alliance Comments at 5-6; and, ESA Comments at 8. Several of 
these commenters request that new reporting requirements be imposed 
to facilitate sellers' ability to perform market power analyses for 
ancillary services markets.
    \40\ PPL Companies Comments at 3, EPSA Comments at 5-6, and 
Portland General Comments at 3-4, Shell Energy Comments at 13-16, 
Powerex Comments at 38-40, and WSPP Comments at 11-12.
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    17. Much of the difficulty in acquiring ancillary service-specific 
data is related to identifying specific resources that are physically 
capable of providing certain ancillary services. For instance, Schedule 
6 Operating Reserve--Supplemental may be provided by generating units 
that are online but partially unloaded, by quick-start generating units 
that are offline or by interruptible load or other non-generation 
resources capable of providing this service.\41\ The associated 
reliability standards definitions indicate that Operating Reserves--
Supplemental must be fully available to serve load within the 
Disturbance Recovery Period, which by default is 15 minutes after a 
reportable disturbance.\42\ Information related to the amount of 
capacity able to start within 15 minutes and information related to the 
quantity of load that is interruptible within 15 minutes may not be 
readily available. In addition, the extent to which a public utility 
decides to provide this service from partially loaded units is a 
decision that public utilities make on a day-to-day basis and is 
dictated in part by the amount of headroom available from the units 
that are committed and dispatched to serve and follow load. Information 
related to this kind of decision making is inherently difficult to 
obtain. This inability to obtain needed information coupled with the 
fact that certain ancillary services, as detailed further below, have 
geographic and other limitations gives rise to our interest in 
considering reforms based on the characteristics of the ancillary 
service to be provided.
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    \41\ See, e.g., Order No. 890-A, FERC Stats. & Regs. ] 31,261, 
Pro Forma OATT at Schedule 6, Operating Reserve--Supplemental 
Reserve Service.
    \42\ See, e.g., NERC Reliability Standard BAL-002-1, Disturbance 
Control Performance at R4.2, available at http://www.nerc.com/files/BAL-002-1.pdf.
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a. Reliance on Existing Indicative Screens
    18. In light of these issues associated with market power analyses 
for specific ancillary services, and the comments asserting that the 
existing market power analyses for sales of energy and capacity may be 
sufficient for ancillary services as well, the Commission has 
considered whether passing the existing market-based rate screens 
described above should create a rebuttable presumption that the seller 
lacks horizontal market power for ancillary services. As discussed 
below, the Commission believes that this may be the case for the two 
imbalance ancillary services (Energy Imbalance and Generator 
Imbalance), but that alternative definitions of the relevant geographic 
market and alternative assumptions for identifying potential competing 
resources within the relevant geographic market may be needed in order 
to apply the existing indicative screens to other ancillary services.
    19. Units capable of providing Energy Imbalance and Generator 
Imbalance do not appear to require any different technical equipment or 
suffer from any different geographical limitations compared to units 
that provide energy or capacity. As one commenter argues, any available 
unit in a given geographic market would appear to be capable of 
providing energy that helps address imbalances in that market.\43\ The 
Commission notes that this position is consistent with the Commission's

[[Page 40418]]

decision in Order No. 890-A to base cost-based imbalance charges in the 
OATT on the incremental cost of the last 10 MW dispatched by the 
transmission provider for any purpose, without imposing any requirement 
that this last 10 MW be based on resources with any particular 
capabilities.\44\ To the extent that there are no unique technical 
requirements or limitations that apply to the provision of Energy 
Imbalance or Generator Imbalance, it would follow that the market-based 
rate screens for energy and capacity would consider the same set of 
units as a market power analysis designed for those two ancillary 
services.
---------------------------------------------------------------------------

    \43\ Shell Energy Comments at 12.
    \44\ See Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 309.
---------------------------------------------------------------------------

    20. Accordingly, the Commission proposes to revise its regulations 
governing market-based rate authorizations to provide that sellers 
passing existing market-based rate analyses in a given geographic 
market should be granted a rebuttable presumption that they lack 
horizontal market power for sales of Energy Imbalance and Generator 
Imbalance ancillary services in that market. Specifically, section 
35.37 of the Commission's regulations would be revised to state that a 
seller would have a rebuttable presumption it lacks market power with 
respect to sales of energy, capacity, energy imbalance service, and 
generator imbalance service if the seller passes the pivotal supplier 
analysis based on annual peak demand of the relevant market and a 
market share analysis applied on a seasonal basis. The Commission 
preliminarily concludes that expanding the rebuttable presumption 
adopted in Order No. 697 for energy and capacity to include Energy 
Imbalance and Generator Imbalance provides adequate protection that 
market-based rates charged by public utilities will be just and 
reasonable and not unduly discriminatory or preferential. The 
Commission notes that this proposal would not constitute a revision to 
the Avista policy. Rather, this proposal merely finds that the existing 
market power screens can be applied to analysis of market power for 
Energy Imbalance and Generator Imbalance. As a result, sellers who pass 
the existing market power screens would not be subject to the sales 
restrictions otherwise required under the Avista policy. The Commission 
seeks comment on this proposal, including the proposed revisions to 
part 35.37(c)(1) of our regulations, and its application to Energy 
Imbalance and Generator Imbalance services. Comments may address, among 
other things, any unique technical requirements or limitations that 
might apply to the provision of the ancillary imbalance services, and 
the Commission's proposal to extend the rebuttable presumption to 
imbalance services.
    21. There appear to be significant technical requirements or 
limitations that apply to the provision of ancillary services other 
than Energy Imbalance and Generator Imbalance such that the existing 
market-based rate screen may not be adequate to capture the potential 
horizontal market power of sellers of these other ancillary services. 
Technical considerations may limit the units capable of providing 
Reactive Supply and Voltage Control, Regulation and Frequency Response, 
Operating Reserve-Spinning, and Operating Reserve-Supplemental services 
as compared to the broader set of units capable of providing energy or 
capacity potentially requiring the identification of a different 
geographic market than the default geographic market used to conduct 
market power analyses for sales of energy and capacity and a change to 
the assumptions used to identify potential competing resources within 
that market. For example, the size of the relevant geographic market 
for a particular ancillary service may be subject to change based on 
system conditions and the need to meet applicable reliability criteria. 
The balancing authority may at times be able to procure ancillary 
services on a system-wide basis, whereas at other times factors may 
require the balancing authority to procure ancillary services on a 
zonal or even more location-specific basis. Further, not every facility 
that has the capability to provide energy will have the capability to 
provide every ancillary service. Also, the procurement may involve 
commercially sensitive internal decision-making that determines what 
proportion of a unit's total capability will be dedicated to a 
particular ancillary service instead of energy and capacity.
    22. With regard to Operating Reserve--Spinning and Operating 
Reserve--Supplemental, the Commission recognizes that resources used to 
provide these services are maintained to convert to energy if needed, 
as with imbalance services. However, minimum ramp rate requirements and 
stringent minimum start-up rates for off-line resources used for 
supplemental reserves apply to the provision of Operating Reserve--
Spinning and Operating Reserve--Supplemental. For on-line resources, 
not all types of units may be capable of extended periods of operation 
below their fully loaded set point, or such operation may be 
prohibitively uneconomic.
    23. With regard to Reactive Supply and Voltage Control, technical 
and geographic considerations generally limit the units capable of 
providing this ancillary service as compared with the broader set of 
units capable of providing energy or capacity. In order to provide 
Reactive Supply and Voltage Control service, conventional synchronous 
generators must be able to vary the voltage level of their electrical 
output. Not all synchronous generators may choose to operate in a way 
that provides Reactive Supply and Voltage Control service. Similarly, 
non-traditional asynchronous resources require some other power 
electronic controls in order to provide this ancillary service, and not 
all owners of asynchronous resources choose to install the needed 
controls. Further, non-generation resources may be technically capable 
of providing this ancillary service with appropriate controls, but they 
may not all choose to install the needed controls. Finally, as 
recognized in numerous venues and proceedings including Order No. 888, 
losses of reactive power during transmission may be significantly 
greater than losses incurred in delivering real power, meaning that 
reactive power must often be supplied from local resources.\45\ 
Therefore, the appropriate relevant geographic market for Reactive 
Supply and Voltage Control service could be smaller than the default 
geographic market discussed above and even within that reduced 
geographic market, not all resources may be capable of competing to 
provide this particular ancillary service. Moreover, conventional 
resources generally require Automatic Generation Control (AGC) 
equipment in order to provide Regulation and Frequency Response 
service, while non-traditional resources require power electronic 
controls that perform like AGC. Not all units have AGC or power 
electronic controls that perform like AGC. Therefore, a different set 
of competing resources might need to be identified within the default 
geographic market for Regulation and Frequency Response service.
---------------------------------------------------------------------------

    \45\ FERC, Principles for Efficient and Reliable Reactive Power 
Supply and Consumption, Docket No. AD05-1-000, at 18 (2005), 
available at http://www.ferc.gov/EventCalendar/Files/20050310144430-02-04-05-reactive-power.pdf. (``Reactive power is difficult to 
transport. At high loadings, relative losses of reactive power on 
transmission lines are often significantly greater than relative 
real power losses * * * Losses in transmission lead to the 
expression that reactive power does not travel well.'').
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    24. The Commission seeks comments on whether the technical 
requirements

[[Page 40419]]

for Operating Reserve--Spinning, Operating Reserve--Supplemental, 
Reactive Supply and Voltage Control, and Regulation and Frequency 
Response would necessitate a market power analysis based on a different 
geographic market or different set of resources as compared to those 
analyzed to determine market power for sales of energy and capacity. If 
so, we seek comment on how the relevant geographic market can be 
identified and how potentially competing resources with the needed 
characteristics can be identified within the relevant geographic 
market. Finally, we seek comment on whether the limited reporting 
requirement and optional market power screen, discussed further below, 
could be applicable for assessing the market power of potential sellers 
of these ancillary services.
b. Optional Market Power Screen
    25. Several commenters to the NOI support the idea of developing 
alternative analyses for measuring market power for ancillary 
services,\46\ while others propose that new reporting requirements be 
imposed to facilitate sellers' ability to perform market power analyses 
for ancillary services markets.\47\ Upon review of these comments, the 
Commission proposes a limited new reporting requirement that would 
provide potential sellers of ancillary services \48\ with the 
information needed to develop market power analyses using an optional 
market power screen solely applicable to ancillary services. 
Specifically, the Commission proposes to require each public utility 
transmission provider to publicly post on its OASIS information as to 
the aggregate amount (MW or MVAR, as applicable) of each ancillary 
service that it has historically required, including any geographic 
limitations it may face in meeting such ancillary service 
requirements.\49\ For example, a hypothetical transmission provider may 
report that it has historically maintained 100 MW of Regulation and 
Frequency Response reserves for its balancing area and 100 MVAR of 
Reactive Supply and Voltage Control in each of two submarkets within 
its balancing authority area.
---------------------------------------------------------------------------

    \46\ See, e.g., California PUC Comments at 5.
    \47\ See, e.g., NGSA comments at 5 and EPSA comments at 3-4.
    \48\ The Commission envisions this optional screen being 
available as a voluntary alternative to the type of market power 
analyses described in Ocean Vista. The Commission also envisions 
permitting this optional screen to be used solely in connection with 
sales of Operating Reserve-Spinning, Operating Reserve-Supplemental, 
Reactive Supply and Voltage Control, and Regulation and Frequency 
Response services. Further, if our earlier proposal regarding 
application of the existing screens to Energy and Generator 
Imbalance services is not ultimately finalized, then we would 
envision permitting the application of this optional screen to those 
ancillary services as well.
    \49\ This requirement would parallel the existing requirement 
for a seller that owns, operates or controls transmission to conduct 
simultaneous transmission import capability studies for its home 
control area and each of its directly-interconnected first-tier 
control areas in order to facilitate market power analyses by all 
sellers in the relevant market. Order No. 697, FERC Stats. & Regs. ] 
31,252 at P 346. The Commission's existing requirements and policies 
with regard to submission of historical data would apply. Therefore, 
any concerns as to possible manipulation of this data should be 
ameliorated.
---------------------------------------------------------------------------

    26. The optional market power screen for an ancillary service would 
then compare the amount of capacity in MWs (or, as applicable, MVARs) 
that a potential seller can dedicate to providing the ancillary service 
in the relevant geographic market with the buyer's reported aggregate 
requirement for that ancillary service, taking into account any 
reported historical locational requirements (e.g., locational 
requirements due to such things as binding transmission constraints or 
the geographic limitations of Reactive Supply). Using this optional 
market power screen, sellers whose available capacity is no more than 
20 percent of the relevant reported aggregate requirement for an 
ancillary service would then receive a rebuttable presumption that they 
lack horizontal market power for the ancillary service in question.
    27. The Commission recognizes that this approach would be an 
alternative to the Commission's historical approach to conducting 
market power analyses, though we believe it is consistent with the 
principles by which we developed our market power analyses. Moreover, 
this approach would be limited solely to market power analyses of 
ancillary services and would be permitted because of the lack of 
publicly-available information on the potential supply of various 
ancillary services in a given geographic market. In Ocean Vista the 
Commission explained that as a general matter, a study of ancillary 
service markets should address the nature and characteristics of each 
ancillary service, as well as the nature and characteristics of 
generators capable of supplying each service, and the study should 
develop market shares for each service.\50\ Of particular relevance 
here, the Commission stated that the market power analysis for 
ancillary services markets should identify the relevant geographic 
market, which could include all potential sellers of the product from 
whom the buyer could obtain the service, taking into account relevant 
factors which may include the other sellers' locations, the physical 
capability of the delivery system and the cost of such delivery, and 
important technical characteristics of the sellers facilities.\51\
---------------------------------------------------------------------------

    \50\ Id. P 1048.
    \51\ Id.
---------------------------------------------------------------------------

    28. The proposed approach discussed above is consistent with these 
principles. Identification of the aggregate requirement for each 
ancillary service within the balancing authority area serves as a proxy 
for the identification of the amount and location of resources that may 
be technically capable of providing the requisite service in the 
relevant geographic market, without requiring resource-specific 
information for resources currently providing the service. The 
Commission has allowed use of proxies for various inputs to the 
indicative screens to simplify or streamline the analyses,\52\ and in 
particular has stated that a seller, where appropriate, can make 
certain simplifying assumptions, such as performing the indicative 
screens assuming that the relevant market has no import capability 
(this was modified in later orders to mean no competing imports) or 
treating the host balancing authority area utility as the only other 
competitor.\53\ Essentially, the proposed proxy would treat the 
resources used historically by the host balancing authority area 
utility as the only other competing resources for purposes of market 
share analysis. This proxy would take into account the nature and 
characteristics of each ancillary service, as well as the nature and 
characteristics of resources capable of supplying each service and any 
limitations such as deliverability that have historically affected 
designation of resources to provide the ancillary service. The proposed 
approach would allow potential third party sellers to compare their 
ancillary service capacity to the capacity that has historically been 
needed to provide the service as shown by the relevant transmission 
provider's OASIS posting of ancillary service

[[Page 40420]]

requirements, and calculate a market share on that basis.
---------------------------------------------------------------------------

    \52\ For example, the Commission has allowed wind generating 
facilities that lack five years of operational data to use a five-
year average regional wind capacity factor based on data reported by 
the Energy Information Administration to de-rate their capacity. See 
Golden Spread Electric Cooperative, Inc., 138 FERC ] 61,208 (2012). 
Additionally, in Order No. 697, the Commission stated that it will 
allow the capacity of energy-limited facilities to be set equal to 
their five-year average historical capacity factor. Order No. 697, 
FERC Stats. & Regs. ] 31,252 at P 344. The Commission also stated 
that it is willing to consider proxy amounts for simultaneous 
transmission import limits. Id. P 381.
    \53\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 321.
---------------------------------------------------------------------------

    29. The Commission preliminarily concludes that this approach will 
foster transparency and competition in the provision of ancillary 
services by providing information for ancillary service sellers to 
perform the market power analyses required by the Commission's rules 
while continuing to provide protection for customers from the potential 
exercise of market power. As with the expansion of the rebuttable 
presumption for energy and capacity to include Energy Imbalance and 
Generator Imbalance proposed above, the optional power market screen 
for ancillary services proposed here would not constitute a revision to 
the Avista policy. Rather, it merely would provide another means of 
demonstrating a lack of market power in sales of ancillary services. As 
a result, sellers who pass this optional market power screen would not 
be subject to the sales restrictions otherwise required under the 
Avista policy.
    30. The Commission seeks comment on whether the proposed limited 
OASIS reporting requirement combined with the opportunity to use an 
optional market power screen for ancillary services, as described above 
and in proposed new parts 37.6(k) and 35.37(c)(5) respectively of our 
regulations, will provide adequate protection that market-based rates 
charged by public utilities will be just and reasonable and not unduly 
discriminatory or preferential. The Commission also requests that 
commenters address the use of the optional screen for Energy and 
Generator Imbalance ancillary services given the Commission's proposal 
above that sellers passing existing market-based rate analyses in a 
given geographic market should be granted a rebuttable presumption that 
they lack horizontal market power for sales of Energy Imbalance and 
Generator Imbalance ancillary services in that market. Additionally, 
the Commission requests comments on the appropriate level of detail to 
include in the proposed reporting requirement. The Commission is aware 
that balancing areas determine reserve requirements in different ways; 
for example, some may have static reserve requirements updated once a 
year, while others specify reserve requirements as a percentage of 
load, meaning that their reserve amounts can change throughout a year. 
The Commission does not at this time intend to change how balancing 
areas determine their reserve amounts. Rather, we wish the proposed 
OASIS reporting requirement to adequately capture whatever method the 
balancing area employs and be detailed enough to support the proposed 
optional market power screen. For example, if ancillary service reserve 
requirements change periodically throughout a year, should the 
associated OASIS posting show the different amounts of reserve 
procurement with their associated time periods or should the OASIS 
posting show a single average reserve procurement amount for the year? 
The Commission also asks for comments on whether the optional market 
power screen should only be implemented on an experimental basis until 
the Commission has more experience with the evolution of ancillary 
service markets and in reviewing the quality of optional market power 
screens.
2. Alternative Cost-Based Mitigation
    31. The NOI also sought comment on alternative mitigation measures 
to the prohibition adopted in Avista with regard to sales to a public 
utility that is purchasing ancillary services to satisfy its own OATT 
requirements to offer ancillary services to its own customers. In 
particular, the Commission sought comment on the possibility of relying 
on an explicit price cap based on the purchasing utility's cost-based 
OATT ancillary service rates or the use of competitive solicitations. 
Based on a review of the resulting comments, the Commission seeks 
further comment regarding whether the specific alternative cost-based 
mitigation measures described below that would allow third-party sales 
to a public utility without showing a lack of market power are adequate 
to ensure that rates charged by third parties for Regulation and 
Frequency Response, Operating Reserve-Spinning, or Operating Reserve-
Supplemental service will be just and reasonable and not unduly 
discriminatory or preferential. In addition, while the Avista policy 
did not apply to Reactive Supply and Voltage Control service, the 
Commission seeks comment on whether third-party sales of Reactive 
Supply and Voltage Control service to a public utility to satisfy its 
own OATT obligations should be permitted under one of the price cap 
options discussed below.
    32. Specifically, the Commission proposes to permit sellers unable 
or unwilling to perform the market power study for ancillary services 
to propose price caps at or below which sales of Regulation and 
Frequency Response, Reactive Supply and Voltage Control, Operating 
Reserve-Spinning, or Operating Reserve-Supplemental service would be 
allowed where the purchasing entity is a public utility purchasing 
ancillary services to satisfy its own OATT requirements to offer 
ancillary services to its own customers. Such a price cap would be 
based on one of the two possible OATT ancillary service rate caps 
discussed below and, as in Avista, we propose that sales under these 
price caps would only be permitted in geographic markets where the 
seller has been granted market-based rate authority for sales of energy 
and capacity. Alternatively, a seller unable to perform a market power 
study for ancillary services could rely on competitive solicitations 
meeting certain minimum requirements in order to make sales in 
geographic markets where the seller has been granted market-based rate 
authority for sales of energy and capacity.
a. Use of Price Caps
    33. As noted above, the Commission in the NOI explored the idea of 
using price caps based on the purchasing utility's OATT rates to serve 
as an alternative mitigation to the Avista policy. Use of price caps or 
other proxies is not unprecedented. For example, the Commission has 
long permitted cost-of-service sellers to propose cost-justified 
ceiling rates to allow the seller to respond quickly to market 
opportunities by discounting below the approved ceiling.\54\ In many 
respects the cost-based ceiling rate umbrella tariffs of decades past 
may have helped begin the development of bilateral markets for energy 
and capacity, and we believe the development of bilateral markets for 
ancillary services today may similarly benefit from the availability of 
appropriate price cap options. Below we propose two options for 
comment.
---------------------------------------------------------------------------

    \54\ See, e.g., Central Maine Power Company, 56 FERC ] 61,200, 
at 61,818-19 (1991) (``We are aware of the argument that, due to the 
need to respond quickly to market changes and opportunities for 
coordination, in some cases transactions must begin before the 
utility has a chance to file the rate reflecting the transaction 
with the Commission. While this argument has some merit, we note 
that many utilities have managed to avoid this problem by having 
tariffs on file that permit transactions to be negotiated subject to 
a cap of 100-percent contribution to fixed costs.'' (emphasis 
added)).
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    34. First, third parties would be permitted to sell to a public 
utility buyer at rates not to exceed the buying public utility 
transmission provider's existing OATT rate for the same ancillary 
service. The Commission anticipates that this option should be 
relatively non-controversial to implement as the buyer's OATT ancillary 
service rates will have already been found to be just and reasonable. 
However, we recognize that in some situations this type of price cap 
may do

[[Page 40421]]

little to signal a buyer's interest in the procurement of ancillary 
services or reflect the actual practices in a region, which may include 
pooling or sharing of reserves. Rather, a policy that relies on the 
rate of a single buyer may serve as a disincentive to the entry of 
additional resources to provide ancillary services and ultimately 
undermine the goal we are trying to achieve of providing sellers some 
flexibility while ensuring just and reasonable rates. The Commission 
also appreciates that an individual buyer's OATT ancillary service 
rates may be higher or lower than the cost of new entry and that they 
do not necessarily signal whether investment is needed to provide the 
service.
    35. Notwithstanding these potential limitations of relying on a cap 
at the buying public utility transmission provider's OATT ancillary 
service rate, the Commission believes that such a cap could provide a 
means of mitigating the potential market power of sellers unable to 
perform a market power analysis. Furthermore, a price cap based on the 
buyer's OATT ancillary service rate may best match the geographic 
limitations of an ancillary service like Reactive Supply and Voltage 
Control, and may provide the simplest route to expanded supply at just 
and reasonable rates for service areas that require more Reactive 
Supply and Voltage Control. The Commission seeks comment on whether 
this cost-based cap would provide an effective alternative to 
imposition of the Avista restriction for mitigating potential market 
power. The Commission also seeks comment on whether this type of cap 
would induce the provision of ancillary services, particularly from 
parties who believe that this cap would be beneficial to their efforts 
to buy or sell specific ancillary services, such as Reactive Supply and 
Voltage Control. We also seek comment on whether the Commission should 
require additional transparency provisions to accompany such a cap 
beyond electric quarterly reports. These provisions may include the 
transmission provider posting its need for ancillary services and any 
seller responses.
    36. Under the second option, third parties could propose to sell a 
given ancillary service to a public utility buyer at rates not to 
exceed the highest public utility transmission provider OATT rate 
within the relevant geographic market for physical trading of the 
ancillary service in question. Under this type of regional price cap, 
the seller (or group of sellers) would be required to file with the 
Commission a proposal that defines the scope of a contiguous geographic 
region that both encompasses the service territory(ies) of the public 
utility transmission provider whose OATT ancillary service rate will 
form the basis for the price cap, and within which trading of the 
ancillary service in question is physically possible. Using the highest 
OATT ancillary service rate as a price cap for a predefined market area 
with the characteristics above may address some of the potential 
limitations of a price cap based on an individual public utility 
transmission provider OATT identified above. Additionally, it may be a 
more reasonable approximation of the cost of new entry within a market 
where physical trading of the ancillary service in question is 
possible.
    37. Such a regional price cap proposal could be proposed for any 
contiguous trading area within which the filer or filers propose to 
make physical trades of ancillary services. The Commission anticipates 
that this trading area often may include the seller's home balancing 
authority area plus first-tier balancing authority areas and possibly 
additional areas where transmission capacity is available. However, the 
Commission is concerned that sellers could seek to define regions that 
are unrealistically broad in order to access a high OATT ancillary 
service rate from outside their region that may not be appropriate 
elsewhere. To prevent this type of distortion, the Commission proposes 
to require price cap sellers to show that the ancillary services in 
question can be physically traded throughout the region they propose 
for a given ancillary service price cap. Such a showing would need to 
take into account the technical characteristics of the ancillary 
service in question in order to demonstrate the physical ability to 
trade in the proposed market area. For example, because of their 
different characteristics, a contiguous geographic region within which 
it is physically possible to trade Operating Reserve-Spinning is likely 
to be much greater than any contiguous geographic region within which 
it is physically possible to trade Reactive Supply and Voltage Control. 
We seek comment on the types of information available to make such a 
showing.
    38. Also, because different sellers proposing to sell the same 
ancillary service could conceivably propose different but overlapping 
trading regions, which might result in multiple regional price caps 
applying to sales in the overlapping areas, the Commission seeks 
comment on whether this type of overlap should be permitted. If not, 
the Commission seeks comment on ways to prevent such overlap in the 
definition of trading regions. In a similar vein, the Commission also 
recognizes the possibility that some sellers may propose a regional 
price cap for a given trading area, while other sellers in the same 
trading area may propose to sell to specific buying public utilities 
under the other price cap option discussed above; a price cap set at 
the buying public utility's relevant OATT ancillary service rate. The 
Commission seeks comment on whether this type of overlap should be 
permitted and, if not, on ways it could be prevented.
    39. As discussed earlier, the Commission recognizes that the 
single-public utility price cap option may best match the geographic 
limitations associated with Reactive Supply and Voltage Control 
service. Should the Commission, as a result, exclude Reactive Supply 
and Voltage Control from the list of ancillary services eligible for a 
regional price cap proposal, meaning that Reactive Supply and Voltage 
Control could only be sold under a price cap based on the buying public 
utility's OATT rate for Reactive Supply and Voltage Control?
    40. The Commission proposes to amend its regulations at part 35.38 
to provide that either of the OATT-based price caps described above can 
be proposed as mitigation of potential horizontal market power in 
ancillary services for those sellers who fail or forego relevant, 
properly defined market power screens for the ancillary service in 
question. The Commission preliminarily concludes that either cap could 
serve as an alternative method of ensuring just and reasonable rates 
for ancillary services that would, unlike the Avista mitigation scheme, 
permit willing buyers and sellers of ancillary services to transact, 
and thus provide a means of increasing the supply of needed ancillary 
services in a timely and cost-effective manner. The Commission seeks 
comment on its proposal, including whether these price caps will 
provide an effective mitigation measure as an alternative to imposition 
of the Avista restriction, and how the Commission should address the 
other questions described above.
b. Competitive Solicitations
    41. The NOI also sought comment regarding whether transmission 
providers' use of open and transparent competitive solicitations could 
facilitate the provision of ancillary services and ensure just and 
reasonable rates. The Commission sought comment regarding whether a 
standardized competitive solicitation process could be developed for 
particular regions or markets.

[[Page 40422]]

    42. While commenters are generally supportive of the use of 
competitive solicitations, some contend that competitive solicitations 
should not be the only option for mitigating market power concerns 
because past solicitations for ancillary services have not always 
produced enough interest to ensure a competitive outcome, and this may 
continue to be the case for some time to come.\55\ WSPP also argues 
that competitive solicitations are probably impractical for short-
notice transactions that would commence within a month or less.\56\ 
However, others appear to suggest that the Commission mandate that all 
ancillary services be procured through competitive solicitations.\57\
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    \55\ Bonneville Comments at 8-9.
    \56\ WSPP Comments at 21-22.
    \57\ ESA Comments at 11-12, PPL Companies Comments at 9, IID 
Comments at 15, and CAREBS Comments at 6.
---------------------------------------------------------------------------

    43. The comments on this issue indicate that competitive 
solicitations may not be appropriate for all transactions and may not 
be sufficient to mitigate potential market power in the sale of 
ancillary services in every circumstance. However, this does not mean 
that competitive solicitations should not be available as an option for 
mitigating potential market power concerns. The Commission proposes to 
allow applicants to engage in sales to a public utility that is 
purchasing ancillary services to satisfy its OATT requirements to offer 
ancillary services to its own customers where the sale is made pursuant 
to a competitive solicitation that meets the following requirements.
    44. Specifically, the Commission has stated that the following four 
guidelines help determine if a competitive solicitation process 
satisfies the principle that no affiliate should receive undue 
preference during any stage of a request for proposals: (1) 
Transparency: the competitive solicitation process should be open and 
fair; (2) definition: the product or products sought through the 
competitive solicitation should be precisely defined; (3) evaluation: 
evaluation criteria should be standardized and applied equally to all 
bids and bidders; and (4) oversight: an independent third-party should 
design the solicitation, administer bidding, and evaluate bids prior to 
the company's selection.\58\
---------------------------------------------------------------------------

    \58\ See, e.g., Allegheny Energy Supply Co. LLC, 108 FERC ] 
61,082 (2004).
---------------------------------------------------------------------------

    45. While the Commission originally issued these guidelines for the 
purpose of preventing undue affiliate preference, we believe they are 
also applicable in the context of using competitive solicitations to 
help mitigate the potential exercise of horizontal market power by 
sellers of ancillary services. However, even if a solicitation process 
meets all of these guidelines, it may still fail to attract sufficient 
numbers of sellers to properly discipline resulting market prices. 
Accordingly, for purposes of a mitigation proposal applicable to 
market-based sales of ancillary services, the Commission proposes to 
require entities filing such a proposal to demonstrate to the 
Commission that the solicitation attracted sufficient seller interest 
to properly discipline market prices. This showing would be required in 
addition to the four criteria listed above. The Commission believes 
that all of these requirements in combination will protect against 
horizontal market power and thereby ensure just and reasonable rates. 
We seek comment on this proposal and encourage commenters to develop 
ideas for ways in which competitive solicitations can be structured to 
accommodate near-term transactions.
    46. Consistent with the discussion above, the Commission proposes 
to amend section 35.38 of its regulations to provide the opportunity 
for public utilities seeking waiver of the Avista restriction to rely 
on competitive solicitations meeting the Commission's requirements for 
transparency, definition, evaluation, oversight, and adequate seller 
interest.

B. Resource Speed and Accuracy in Determination of Regulation and 
Frequency Response Reserve Requirements

    47. In addition to exploring potential changes to the Commission's 
requirements for market-based rate authority discussed above, the NOI 
also sought comment on whether the various cost-based compensation 
methods for Regulation and Frequency Response service that exist in 
regions outside of the current organized markets could be adjusted to 
address the issues identified in the proceeding that led to the 
issuance of Order No. 755.\59\ In that proceeding, the Commission 
required changes to compensation mechanisms for Regulation and 
Frequency Response service in the RTO and ISO markets to ensure that 
all resources providing service are compensated in a just and 
reasonable and not unduly discriminatory manner. While acknowledging 
that the specific reforms ultimately adopted in Order No. 755 would not 
apply outside of RTOs and ISOs, the NOI questioned whether the 
underlying goal of better valuing the benefits of faster, more accurate 
provision of Regulation and Frequency Response service could be 
achievable in other ways outside of RTOs and ISOs.
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    \59\ Order No. 755, FERC Stats. & Regs. ] 31,324 at P 68 
(``faster-responding resources have the potential to lower frequency 
regulation capacity requirements, thereby improving market 
efficiencies'').
---------------------------------------------------------------------------

    48. Specifically, the NOI sought comment on: (1) How a cost-based 
cap for Regulation and Frequency Response service in the WSPP Agreement 
\60\ could be structured to reflect an individual resource's 
performance; (2) whether transmission customers that self-supply 
Regulation and Frequency Response service could be permitted to 
determine the amount of capacity they procure based on the third-party 
resource's performance capability; and (3) any other way to extend the 
goals of the Frequency Regulation Compensation NOPR,\61\ which 
ultimately resulted in Order No. 755, outside of the ISOs and RTOs.
---------------------------------------------------------------------------

    \60\ 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 (D.C. Cir. 1992), order on remand, 
66 FERC ] 61,201 (1994). Prior to 1991, the WSPP Agreement was used 
for three years on an experimental basis. See Pacific Gas and 
Electric Co., 50 FERC ] 61,339 (1990) (extending the initial two-
year period of the WSPP Agreement for an additional year). 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. 
See Western Sys. Power Pool, 122 FERC ] 61,139 (2008) (finding that 
it is not just and reasonable to allow a seller to use the WSPP-wide 
``up to'' demand charge as a ceiling rate in markets where the 
seller does not have market-based rate authority unless such a 
seller can cost-justify the use of the ``up to'' demand charge based 
on its own fixed 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.
    \61\ Frequency Regulation Compensation in the Organized 
Wholesale Power Markets, FERC Stats. & Regs. ] 32,672 (2011) 
(Frequency Regulation Compensation NOPR). Order No. 755 had not yet 
issued at the time of the NOI in this proceeding.
---------------------------------------------------------------------------

    49. Most of the more concrete NOI comments on this issue focus on 
the second question above: whether transmission customers that self-
supply Regulation and Frequency Response

[[Page 40423]]

service could be permitted to determine the amount of capacity they 
procure based on the third-party resource's performance capability.\62\ 
Some commenters suggest that customers choosing to self-supply 
Regulation and Frequency Response service from faster-acting resources 
should be allowed to self-supply a lower volume of regulation 
capacity.\63\ Powerex suggests that each balancing authority be 
required to maintain well-defined criteria under which a transmission 
customer self-providing ancillary service reserves can adjust the level 
of reserves based on the ramping capability of the resources it 
uses.\64\ Bonneville states that, in such circumstances, the balancing 
authority should make the determination as to the appropriate level of 
capacity procurement, not the customer itself.\65\
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    \62\ See, e.g., Bonneville Comments at 9-10, California Storage 
Alliance Comments at 14-19, ESA Comments at 27-28, Powerex Comments, 
Appendix A at 8, and A123 Comments at 2-4. Other comments included 
WSPP's suggestion that a rate cap proposal could use the two-part 
rate design described in the Frequency Regulation NOPR, but WSPP 
does not provide any details regarding how such a rate design could 
be structured. WSPP Comments at 26-27.
    \63\ California Storage Alliance Comments at 14-17; ESA Comments 
at 27-28.
    \64\ Powerex Comments, Appendix A at 8.
    \65\ Bonneville Comments at 10.
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    50. Under the existing requirements of the pro forma OATT, each 
public utility transmission provider is required to provide its 
transmission customers with the option of self-supplying certain 
ancillary services, including Regulation and Frequency Response 
service.\66\ This self-supply option has been clear since Order No. 888 
and, therefore, public utility transmission providers must be prepared 
to provide self-supply requirements on request from a transmission 
customer. However, the Commission to date has not addressed the extent 
to which such requirements should reflect the characteristics of 
particular resources being used to provide Regulation and Frequency 
Response service.
---------------------------------------------------------------------------

    \66\ See, e.g., Order No. 888, FERC Stats. & Regs. ] 31,036 at 
31,716; pro forma OATT, Original Sheet Nos. 20-21 and Schedule 3, 
Original Sheet No. 113.
---------------------------------------------------------------------------

    51. The Commission proposes to require that each public utility 
transmission provider submit provisions for inclusion in its OATT that 
take into account the speed and accuracy of regulation resources in 
determining its Regulation and Frequency Response reserve 
requirements.\67\ These provisions must include a description of how 
the public utility transmission provider would make adjustments to the 
capacity requirement when a customer opts to self-supply its 
requirements, including through purchases from third-parties, using 
resources with speed and accuracy characteristics that differ from the 
set of resources otherwise being used for Regulation and Frequency 
Response. This description could include the set of resources the 
public utility transmission provider uses to provide Regulation and 
Frequency Response service, indicating the capacity typically set aside 
from each resource and the ramp rate associated with each resource. The 
description needs to provide enough detail to allow an entity wishing 
to self-supply to compare the resources it proposed to use to the 
resources the public utility transmission provider is using to provide 
Regulation and Frequency Response service. Presumably, this adjustment 
could be in either direction: down if the customer self-supplies with 
faster or more accurate resources or up if it uses slower or less 
accurate resources.
---------------------------------------------------------------------------

    \67\ The Commission acknowledges that each balancing authority 
is responsible for determining its reserve requirements in order to 
comply with relevant NERC reliability standards, and that sometimes 
an individual OATT transmission provider may be its own balancing 
authority and other times it may be part of a larger balancing 
authority. The Commission also notes that a new standard, BAL-003-1 
(Frequency Response and Frequency Bias Setting), is currently under 
development by NERC stakeholders and may assign a frequency response 
obligation to each balancing authority or reserve sharing group and 
require each balancing authority or reserve sharing group to use an 
appropriate frequency bias setting in its ACE equation and to 
achieve an adequate annual frequency response measure. While 
frequency response is distinguished from frequency regulation by the 
manner in which it is controlled (see, e.g., Order No. 755, FERC 
Stats. & Regs. ] 31,324 at n.5), this standard may also be relevant 
to a balancing authority's determination of its overall reserve 
requirements.
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    52. The Commission preliminarily finds that accounting for speed 
and accuracy in a public utility transmission provider's determination 
of Regulation and Frequency Response reserve requirements is necessary 
to address the potential for undue discrimination against customers 
choosing to self-supply their Regulation and Frequency Response needs, 
including through purchases from third-parties. The Commission is 
concerned that a public utility transmission provider could engage in 
undue discrimination by requiring such customers to procure a different 
amount of regulation reserves than the particular speed and accuracy 
characteristics of the resources in question justify. Accordingly, the 
Commission proposes to amend its regulations at part 35.28 to require 
that public utility transmission providers amend their OATTs at 
Schedule 3 (Regulation and Frequency Response Service) to explain how 
they will take into account the speed and accuracy of regulation 
resources in determining Regulation and Frequency Response reserve 
requirements. The Commission acknowledges that each public utility 
transmission provider has unique needs related to Regulation and 
Frequency Response reserve requirements and, accordingly, may account 
for speed and accuracy in different ways. Therefore, the Commission 
does not at this time seek to mandate a particular methodology but 
instead expects that it would evaluate each proposed determination 
relevant to Regulation and Frequency Response reserve requirements on a 
case-specific basis.
    53. The Commission seeks comment on this proposal, including 
comment on how speed and accuracy can be taken into account in the 
determination of Regulation and Frequency Response reserve 
requirements, and the Commission's preliminary conclusion that 
requiring transparency in the determination of Regulation and Frequency 
Response reserve requirements will help prevent undue discrimination in 
the form of public utility transmission providers requiring self-
supplying customers to procure a different amount of regulation 
reserves than the particular speed and accuracy characteristics of the 
resources in question justify.
    54. Further, in consideration of the comments regarding the ability 
of a customer to self-supply ancillary services, we take this 
opportunity to remind public utility transmission providers that they 
are already required to post on their public Web sites all rules, 
standards, and practices, to the extent they exist, that relate to 
transmission service. This includes the provision of ancillary services 
which are necessary to the provision of transmission service. As such, 
the obligation is clear and we see no need at this time to propose 
reforms.\68\
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    \68\ 139 FERC ] 61,246.
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C. Accounting and Reporting for Energy Storage Operations

    55. Finally, the NOI also asked about the Commission's accounting 
and reporting requirements for energy storage operations. Comments were 
sought on what changes, if any, should be made to the Commission's 
accounting and reporting regulations to provide for energy storage 
services, assets and operations. Comments were received from public 
utilities, industry associations, government agencies, and others. As 
noted in the NOI, the accounting regulations currently found in the 
USofA and the related reporting

[[Page 40424]]

requirements were developed to capture financial and operational 
information along traditional primary business functions--production, 
transmission, and distribution of electric energy.\69\ Further, as also 
noted, energy storage assets can have operating characteristics of each 
of these functions and some may be capable of performing multiple 
functions simultaneously.\70\ Accordingly, entities using energy 
storage assets may seek multiple methods of cost recovery for their 
investments in and use of a single energy storage asset to provide 
various utility services.\71\
---------------------------------------------------------------------------

    \69\ NOI, 135 FERC ] 61,240 at P 25.
    \70\ Id.
    \71\ Id.
---------------------------------------------------------------------------

    56. Numerous comments were received regarding the need for updating 
the USofA and Form Nos. 1 and 1-F for the accounting and reporting of 
public utilities. Most commenters are supportive of making amendments 
to accommodate energy storage transactions. However, some commenters 
indicate that the Commission's current accounting and reporting 
requirements sufficiently accommodate these types of transactions.
    57. In general, commenters that support amending the current 
accounting and reporting requirements indicate that the operating 
nature of energy storage assets is different from typical electric 
plant assets. These commenters indicate that energy storage assets can 
be used to serve multiple purposes--production, transmission, or 
distribution--whereas traditional electric plant assets only serve one 
purpose. Consequently, they explain that this difference in 
capabilities can mandate, in certain cases, that the energy storage 
assets be accounted for differently than traditional electric plant 
assets. These commenters indicate that changes to the accounting and 
reporting requirements are needed to address concerns about the 
potential for cross-subsidization and double or over-recovery of costs 
in instances where an energy storage asset is simultaneously included 
in cost-based and market-based rates. Most of these commenters 
recommend specific accounting and reporting amendments that could 
assist with protecting against these concerns and certain other 
commenters in this group expressed that the concern existed but offered 
no recommendations. For example, Electricity Consumers did not propose 
specific accounting changes; however, it indicates that it supports 
accounting treatments that could enhance cost transparency to protect 
against double-recovery of costs.\72\
---------------------------------------------------------------------------

    \72\ Electricity Consumers Comments at 8.
---------------------------------------------------------------------------

    58. Several commenters recommend that the Commission create a new 
energy storage functional classification with associated plant and 
operation and maintenance (O&M) expense accounts for energy storage 
assets and operations. TAPS states that because the functional use of a 
given energy storage facility may change over time and may not fit 
neatly into any one existing functional category, and because energy 
storage facility costs may come to be recovered through storage-
specific rate schedules, the only transparent and administratively 
efficient way to account for energy storage plant costs is by adding 
new accounts to the USofA.\73\ TAPS contends that the overall objective 
of any changes should be to support either effective cost-based 
regulation of jurisdictional services provided using energy storage 
resources, or effective market power monitoring and mitigation.\74\ 
APPA agrees with TAPS' comments.\75\
---------------------------------------------------------------------------

    \73\ TAPS Comments at 13.
    \74\ Id. at 12.
    \75\ APPA Comments at 7.
---------------------------------------------------------------------------

    59. The Public Interest Organizations state that a separate asset 
class may prove the best way to provide full and comparable treatment 
for energy storage facilities.\76\ NGK/TI argues that a new functional 
classification is needed because energy storage assets are functionally 
distinct from traditional production, transmission, and distribution 
assets and energy storage functions cross-cut these traditional 
functions.\77\
---------------------------------------------------------------------------

    \76\ Public Interest Organizations Comments at 12.
    \77\ NGK/TI Comments at 10.
---------------------------------------------------------------------------

    60. Other commenters recommend that the Commission create new plant 
and O&M expense accounts within the existing functional classifications 
of production, transmission, and distribution rather than creating a 
new functional classification specifically for energy storage. 
FirstEnergy states that new energy storage technologies may provide 
transmission, distribution, or production services, and the current 
USofA adequately provides for facilities and activities that provide 
these functions. However, FirstEnergy states that the USofA does not 
provide the necessary accounting transparency for new storage 
technologies. FirstEnergy recommends that the Commission establish new 
accounts within the currently established functions to provide 
additional accounting transparency and detail regarding the plant costs 
and O&M expenses of energy storage facilities that serve these 
functions.\78\ FirstEnergy states that the accounting should strive for 
transparency by identifying each type of asset with the primary 
function it serves and aligning the expenses associated with the asset 
with the revenues it provides. SDG&E contends that energy storage 
assets should be classified in the existing classifications as 
production, transmission, or distribution as determined by the owner of 
the assets and consistent with the jurisdictional nature of the service 
that the energy storage device provides.\79\
---------------------------------------------------------------------------

    \78\ FirstEnergy Comments at 5.
    \79\ SDG&E Comments at 4.
---------------------------------------------------------------------------

    61. Commenters opposed to amending the current accounting and 
reporting requirements generally argue that the existing requirements 
adequately accommodate energy storage technologies. CAREBS asserts that 
the Commission's goal should be to use, where possible, existing 
accounting methods rather than invent new ones. SolarReserve argues 
that because many sales of ancillary services would be made under 
sellers' market-based rate authority, the sellers would have waivers of 
the accounting and reporting requirements at issue here.\80\ Thus, in 
SolarReserve's opinion, there is no need to amend the Commission's 
accounting and reporting requirements.
---------------------------------------------------------------------------

    \80\ SolarReserve Comments at 5.
---------------------------------------------------------------------------

    62. California Storage Alliance and ESA indicate that if the 
Commission decides against creating new energy storage plant accounts 
and instead proposes to use existing plant accounts to account for 
energy storage resources, there would need to be changes to existing 
plant accounts to better capture energy storage plant costs. In this 
instance, California Storage Alliance and ESA recommend that the 
Commission revise the instructions of current plant accounts to 
explicitly include energy storage resources.\81\
---------------------------------------------------------------------------

    \81\ California Storage Alliance Comments at 29; and ESA 
Comments at 36.
---------------------------------------------------------------------------

    63. Responding to concerns about the potential for cross-
subsidization in instances where an energy storage resource 
simultaneously provides multiple services under cost-based and market-
based cost recovery mechanisms, EEI reasons that the Commission's 
current policies can address concerns of cross-subsidization. EEI 
states that a jurisdictional entity should separately account for 
services sold under cost-based rates and those that are sold under 
market-based rates to prevent unfair market advantages through 
subsidization.\82\ Further, EEI

[[Page 40425]]

states that if an energy storage device is providing a transmission 
service then it should be accounted for based on its primary use when 
it was initially placed in service.\83\ California PUC makes a similar 
argument indicating that the energy storage device should be accounted 
for based on its intended use within a project.
---------------------------------------------------------------------------

    \82\ EEI Comments at 10.
    \83\ Id.
---------------------------------------------------------------------------

    64. EEI and other commenters also argue that energy storage 
technologies are in an early stage of the technology and that the 
Commission should wait before implementing new accounting or reporting 
requirements for energy storage assets. California PUC asserts that due 
to the complexity of the technologies and their multiple potential 
uses, to avoid disruption of the existing functional classification 
system the Commission should use a case-by-case exception approach to 
determine the appropriate classification.\84\
---------------------------------------------------------------------------

    \84\ California PUC Comments at 7.
---------------------------------------------------------------------------

1. Proposed Accounting Requirements
    65. While the Commission's accounting and reporting requirements 
associated with the USofA do not dictate the ratemaking decisions of 
this Commission or State Commissions, these accounting and reporting 
requirements nevertheless support the rate oversight needs of both this 
Commission and State Commissions. Accordingly, the Commission strives 
to ensure that its accounting and reporting requirements keep pace with 
the evolution of the electric industry. As the industry has evolved, 
the Commission has relied on its accounting and reporting requirements 
applicable to existing public utilities \85\ (i.e., principally 
investor-owned utilities) to obtain information about an entity's 
financial condition and results of operations. This information is 
important in developing and monitoring rates, making policy decisions, 
compliance and enforcement initiatives, and informing the Commission 
and the public about the activities of entities that are subject to 
these accounting and reporting requirements.\86\
---------------------------------------------------------------------------

    \85\ 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 (2011) (Definition No. 
29).
    \86\ 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.
---------------------------------------------------------------------------

    66. The Commission has required public utilities to continue to 
prepare their financial statements in accordance with the accounting 
requirements of the USofA, as it can accommodate most transactions and 
events affecting these entities. 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 produce, transmit, or 
distribute electric energy. In addition, public utilities must also 
record and classify 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 Form 
Nos. 1, 1-F, and 3-Q reports that are maintained in accordance with the 
accounting requirements of the USofA.
    67. As stated in the NOI, the roles of traditional production, 
transmission, and distribution assets are generally well understood and 
each has established method(s) of accounting and reporting; however, 
the same is not necessarily true of energy storage assets which can 
operate in ways that resemble production, transmission, and/or 
distribution.\87\ Moreover, it may be possible for some energy storage 
assets to provide some combination of production, transmission, and 
distribution services simultaneously. Accordingly, public utilities 
using energy storage assets may seek multiple methods of cost recovery 
for their investments in, and use of, the assets to provide various 
utility services.\88\ Consequently, due to the potential to use certain 
energy 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 sought 
comment in the NOI on whether current accounting and reporting 
requirements for activities and costs for the operation of energy 
storage resources provide sufficient transparency.
---------------------------------------------------------------------------

    \87\ NOI, 135 FERC ] 61,240 at P 25.
    \88\ Id.
---------------------------------------------------------------------------

    68. After analyzing all comments received and considering the 
Commission's informational needs, the Commission has determined that 
the current accounting and reporting requirements do not provide 
sufficiently transparent information on the activities and costs of new 
energy storage operations. Consequently, the Commission proposes to 
amend the USofA and Form Nos. 1, 1-F, and 3-Q to provide financial and 
operational information on energy storage assets.
    69. The Commission proposes to add new electric plant and O&M 
expense accounts to record the installed cost and operating and 
maintenance cost of energy storage assets and a new account to record 
the cost of power purchased for use in energy storage operations. In 
addition, the Commission proposes to amend the Form Nos. 1, and 1-F to 
include the new accounts and amended schedules to report statistical 
and operational information on energy storage operations. Further, the 
Commission proposes to amend a schedule of the Form No. 3-Q to include 
the proposed new account to record the cost of power purchased for use 
in energy storage operations. The Commission seeks comment on these 
proposed amendments, including whether the proposed changes will 
provide sufficiently transparent information on the activities and 
costs of new energy storage operations.
    70. Numerous commenters responding to the NOI indicate that the 
Commission's current accounting and reporting requirements for new 
energy storage assets are not sufficiently transparent. Many of these 
commenters suggest that the Commission address this matter by either 
creating new plant and O&M expense accounts to specifically account for 
energy storage assets and operations in the existing functional 
classifications of production, transmission, and distribution, or 
creating a new separate functional classification for energy storage 
operations and new associated energy storage plant and O&M expense 
accounts. While both options would satisfy the Commission's and the 
public's need for detailed and transparent financial and operation 
information on public utilities' use of energy storage resources to 
provide jurisdictional services, the latter option is unnecessary 
because the existing functional classifications can adequately support 
energy storage operations. Furthermore, creating a new functional 
classification does not provide additional benefits compared to 
creating new accounts within existing classifications. Our proposed 
amendments to the Form Nos. 1 and 1-F would require utilities with 
energy storage operations to report detailed financial and operation 
information on energy storage assets and activities in new schedules 
for all functions.\89\ Thus, using existing functional classifications 
provides the same level of transparency as would creating a new 
functional class.
---------------------------------------------------------------------------

    \89\ See, discussion of proposed amendments to Form Nos. 1 and 
1-F at PP 101-106.
---------------------------------------------------------------------------

    71. Moreover, the Commission understands that the energy storage 
industry continues to evolve, and as some commenters observe, the use 
of energy storage resources in large-scale

[[Page 40426]]

public utility operations is at an early stage of development. However, 
commenters recommending that the Commission wait until the industry is 
more mature before imposing any accounting and reporting requirements 
for energy storage assets and operations disregard the current need for 
certainty in the accounting and reporting treatment for energy storage 
resources and operations. Uniform, transparent and consistent reporting 
of information on energy storage operations by public utilities is 
essential, especially by those seeking to recover costs of energy 
storage services in cost-based rates. This need for information is 
heightened by the chance that public utilities could seek to 
simultaneously recover service costs under cost-based and market-based 
rate mechanisms using a single energy storage asset.\90\
---------------------------------------------------------------------------

    \90\ The Commission has not to date received any proposals from 
public utilities that simultaneously seek to recover costs under 
cost-based and market-based rate mechanisms using a single energy 
storage asset, but the Commission remains open to innovative 
solutions and will evaluate proposals on a case-by-case basis.
---------------------------------------------------------------------------

    72. Transparency improvements achieved through revisions to the 
existing accounting and reporting requirements will enhance the 
Commission's and other form users' ability to make a meaningful 
assessment of a utility's cost of service and rates. Further, this will 
enable the Commission and others to better monitor for cross-
subsidization. The overarching purpose of these proposed accounting and 
reporting amendments is to provide useful financial and operational 
information to regulatory agencies and other users of public utilities' 
financial statements by establishing uniform accounting and reporting 
requirements for energy storage assets and operations.
    73. The Commission endeavors to achieve a balance between the 
benefits of revising its accounting and reporting regulations and the 
imposition of any additional burden on utilities. Information that 
would be reported for energy storage assets and operations differs 
little from other data public utilities maintain under the USofA. If a 
utility owns and operates these energy storage assets, reporting 
information on them in the proposed accounts and FERC form schedules 
should not be burdensome. Requiring utilities to classify and account 
for energy storage assets and operations under existing functional 
classifications rather than a new one addresses the Commission's and 
the public's need for detailed and transparent information and lessens 
the implementation burden on public utilities and licensees subject to 
Commission accounting and reporting requirements.
    74. SolarReserve argues that the accounting and reporting 
requirements should not be amended because many sales of ancillary 
services would be made under the sellers' market-based rate authority. 
This argument is unconvincing. While public utilities using energy 
storage resources that are granted market-based rate authority by the 
Commission may seek waivers of the accounting and reporting 
requirements at issue here, there are instances when public utilities 
may not seek or fail to be granted waiver of the requirements. 
Additionally, previously granted waivers may be rescinded where a 
seller is found to have market power (or where the seller accepts a 
presumption of market power) and the seller proposes cost-based rate 
mitigation or the Commission imposes cost-based rate mitigation. Also, 
public utilities seeking to only recover storage costs under cost-based 
rates will be subject to these accounting and reporting requirements.
    75. Furthermore, in instances where public utilities seek to 
simultaneously recover costs under cost-based and market-based rates, 
the Commission proposes that the entities be required to account for 
and report their operations in accordance with the Commission's 
accounting and reporting requirements to facilitate development and 
monitoring of the cost-based portion of the rates. In addition, we 
propose that public utilities currently providing jurisdictional 
services and recovering costs of the services under market-based rates 
that have been granted waiver of the accounting and reporting 
requirements that seek recovery of a portion of service costs under 
cost-based rates, be required to forego the previously issued waiver 
and account for and report all cost and operational information to the 
Commission in accordance with its accounting and reporting 
requirements. In this instance, public utilities would be required to 
account for and report costs sought to be recovered on a cost-based and 
market-based basis. We seek comment on these proposals. Also, we seek 
comment on whether there should be a percentage of cost recovery 
threshold \91\ or other determining factor that triggers the accounting 
and reporting obligations in this situation, or should any instance of 
multiple cost recovery, regardless of the percentage of a utility's 
total costs, trigger the accounting and reporting obligations. If a 
percentage threshold should apply, we seek comment with supporting 
rationale on what would be an appropriate threshold percentage.
---------------------------------------------------------------------------

    \91\ For example, a public utility with 90 percent of its 
service costs recovered under market-based rates and the remaining 
10 percent recovered under cost-based rates.
---------------------------------------------------------------------------

    76. Except as discussed above, the proposed amendments to the 
accounting and reporting regulations are not intended to affect the 
Commission's policy on market-based rate authority as provided in Order 
No. 697 or its historical practice of granting waiver of the accounting 
and reporting regulations of 18 CFR parts 41, 101, and 141 to certain 
entities with market-based rate authority. In Order No. 697, the 
Commission concluded that the costs of complying with the USofA 
requirements and, specifically Parts 41, 101, and 141 of the 
Commission's regulations, outweigh any incremental benefits of such 
compliance where the seller only transacts at market-based rates.\92\ 
These proposed accounting and reporting rules do not change that 
conclusion. However, the Commission notes that entities authorized to 
make market-based rate sales, irrespective of accounting or other 
waivers, must file electric quarterly transaction reports regarding 
their transactions pursuant to Order No. 2001.\93\
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    \92\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 985.
    \93\ Revised Public Utility Filing Requirements, Order No. 2001, 
FERC Stats. & Regs. ] 31,127 (2002), reh'g denied, Order 2001-A, 100 
FERC ] 61,074 (2002), reh'g denied, Order No. 2001-B, 100 FERC ] 
61,342 (2002), order directing filings, Order No. 2001-C, 101 FERC ] 
61,314 (2002), order directing filings, Order No. 2001-D, 102 FERC ] 
61,334, order refining filing requirements, Order No. 2001-E, 105 
FERC ] 61,352 (2003), clarified, Order No. 2001-F, 106 FERC ] 61,060 
(2004), order on reh'g, Order No. 2001-G, 120 FERC ] 61,270 (2007), 
order on reh'g, Order No. 2001-H, 121 FERC ] 61,289 (2007), order 
revising filing requirements, Order No. 2001-I, FERC Stats. & Regs. 
] 31,282 (2008).
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    77. At this time, the proposed accounting and reporting rules do 
not impose additional accounting or reporting requirements for 
hydroelectric pumped storage plant. The existing accounting and 
reporting standards use subaccounts for pumped storage under the 
functional classification of production, which is the only Commission-
approved jurisdictional use of pumped storage to date. While the 
Commission has no basis to believe it is impossible to use large-scale 
pumped storage technologies to perform transmission or distribution 
functions as well, to date, no pumped storage developer has 
successfully demonstrated such a non-``production'' use to the 
Commission. This stands in contrast to the track record for smaller-
scale energy storage technologies, where one battery developer has 
successfully

[[Page 40427]]

supported a non-production, transmission use for its project.\94\ The 
Commission remains open to future additions of pumped storage 
subaccounts to the transmission and distribution functions if 
appropriate, but at this time the Commission believes that the assets 
and operations of this pumped storage equipment are sufficiently 
accounted for by the existing FERC accounts and schedules of the Form 
Nos. 1, 1-F and 3-Q.\95\
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    \94\ See Western Grid Development, LLC, 130 FERC ] 61,056, reh'g 
denied, 133 FERC ] 61,029 (2010) (Western Grid).
    \95\ See FERC Account Nos. 330-337 and 535-545.1, 18 CFR part 
101 (2011); and Form Nos. 1, 1-F, and 3-Q, 18 CFR part 141 (2011).
---------------------------------------------------------------------------

a. Electric Plant Accounts
    78. The existing primary plant accounts do not explicitly provide 
for recording the original cost of energy storage assets. This can lead 
to inconsistent accounting and reporting for these assets by utilities 
subject to the accounting and reporting requirements, making it 
difficult for the Commission and others to determine costs related to 
energy storage assets for cost-of-service rate purposes. In addition, 
the lack of transparency affects interested parties' and including the 
Commission's ability to monitor these companies operations to prevent 
and discourage cross-subsidization between cost-based and market-based 
activities.
    79. To provide more transparency for the costs of energy storage 
assets, as well as to address the possibility of inconsistent 
accounting and reporting, we propose creating a new electric plant 
account and amending two existing electric plant accounts to record the 
installed cost of energy storage equipment owned by public utilities 
and licensees. Specifically, we propose a new account within the 
production functional classification and amending existing accounts 
within the transmission and distribution functional classifications.
    80. The proposed plant account would be Account 348, Energy Storage 
Equipment--Production, and the accounts we propose to amend are 
existing Account 351, [Reserved], and Account 363, Storage Battery 
Equipment. Account 351 is a reserve account and is not currently being 
used. The Commission proposes to rename Account 351 as Energy Storage 
Equipment--Transmission. The current instructions of Account 363 
provides for the inclusion of the cost of storage battery equipment 
used for the purpose of supplying electricity to meet emergency or peak 
demands. The Commission proposes to amend the instructions of Account 
363 to expand the type of energy storage assets that can be recorded in 
the account and to recognize the unique operating characteristics of 
energy storage assets, which may provide services other than only 
supplying electricity.\96\ In addition, we also propose to rename 
Account 363 as Energy Storage Equipment--Distribution.
---------------------------------------------------------------------------

    \96\ For example, as a distribution resource recorded in the 
account the asset could assist with voltage regulation which may 
require it to absorb electricity rather than only supply it at 
times.
---------------------------------------------------------------------------

    81. The Commission proposes that the instructions to the accounts 
provide for recording the cost of installed energy storage assets based 
on the function or purpose the equipment serves. Further, we propose 
that in instances where an energy storage asset is used to perform more 
than one function or purpose, the cost of the asset shall be allocated 
among production, transmission, and distribution plant based on the 
services provided by the asset and the allocation of the asset's cost 
through cost based rates approved by a relevant regulatory agency, 
federal or state. For example, if a relevant State Commission under its 
own retail rate-setting authority approves the recovery of 25 percent 
of the cost installed of the storage device through the distribution 
component of retail rates, then we would expect 25 percent of the cost 
installed of the asset to be allocated to distribution plant for 
accounting and reporting purposes and we would expect distribution-
related O&M and other accounting and reporting entries to likewise 
match relevant decisions made in the State Commission rate proceeding. 
If other portions of the cost installed are also approved for inclusion 
in cost-based rates at either a state or federal level, then the 
relevant decisions in those state or federal proceedings would apply to 
accounting and reporting entries as well. The Commission seeks comments 
on these aspects of our proposal.
    82. Additionally, the Commission proposes that the original cost of 
an energy storage asset and other amounts associated with the original 
cost of the asset (e.g., accumulated depreciation expenses and 
accumulated deferred income taxes) initially allocated to specific FERC 
accounts and later reallocated to other FERC accounts based on services 
provided by the asset and cost recovery be accounted for in accordance 
with Electric Plant Instruction No. 12, Transfers of Property.\97\ 
Accordingly, we propose that if the costs of an energy storage asset 
are included in the development of cost-based rates, then the same 
allocation of costs the primary rate-setting body used for rate 
development will also be used to allocate the original cost of the 
energy storage asset among the various functions for accounting and 
reporting purposes. The Commission seeks comment on these proposals, 
including the accounting for the transfer of costs associated with an 
energy storage asset from one functional classification to another. 
Finally, we propose that the cost of energy storage assets be charged 
to depreciation expense using the depreciation rates developed for each 
function.
---------------------------------------------------------------------------

    \97\ 18 CFR part 101 (2011).
---------------------------------------------------------------------------

    83. Since some energy storage equipment may perform multiple 
functions on the grid, we propose that public utilities be required to 
maintain records identifying the types of functions each individual 
energy storage asset supports and performs.
    84. Additionally, the Commission proposes that costs to install 
energy storage equipment, along with power purchased or internally 
generated to energize the equipment to prepare it for service, be 
capitalized as a component cost of the equipment on the first 
installation only. This includes costs associated with power purchased 
and internally generated to test the equipment in preparation for 
utility service prior to it becoming ready for or placed in 
service.\98\ Further, we propose that earnings resulting from revenue 
received or earned for energy storage operations during test runs be 
credited to the cost of construction of the project.\99\
---------------------------------------------------------------------------

    \98\ See Electric Plant Instruction No. 9(D), Equipment, 18 CFR 
part 101 (2011).
    \99\ See, e.g., Electric Plant Instruction No. 3(A)(18), 
Earnings and Expenses During Construction, 18 CFR Part 101 (2011).
---------------------------------------------------------------------------

    85. Certain energy storage assets are capable of being moved from 
one location to another. These mobile assets are suitable for a wide 
range of applications, including emergency power and reliability, among 
other uses. Labor, materials and other costs are associated with moving 
these energy storage assets from one location to another location, 
resetting and preparing them to provide service, and purchasing or 
self-generating power to reenergize the assets. We propose that any 
costs incurred to remove, relocate, reset or reenergize an energy 
storage asset after it was first placed into utility service would not 
be chargeable to the energy storage equipment accounts as a cost 
component of the energy storage asset. Instead, the Commission proposes 
that such costs be accounted for as a

[[Page 40428]]

production, transmission, or distribution expense based on the services 
provided by the energy storage asset and recovery of the asset's cost 
through rates, in the accounts that follow.\100\
---------------------------------------------------------------------------

    \100\ These proposed energy storage O&M expense accounts are 
discussed in more detail below at section 1(c).
---------------------------------------------------------------------------

    86. The Commission proposes requiring that expenses other than 
power expenses for removing, relocating or resetting energy storage 
plant serving a production function be charged to Account 548.1, 
Operation of Energy Storage Equipment, and Account 553.1, Maintenance 
of Energy Storage Equipment. We propose requiring that expenses other 
than power expenses for removing, relocating or resetting energy 
storage plant serving a transmission function be charged to Account 
562.1, Operation of Energy Storage Equipment, and Account, 570.1, 
Maintenance of Energy Storage Equipment. Also, we propose requiring 
that expenses other than power expenses for removing, relocating or 
resetting energy storage plant serving a distribution function be 
charged to Account 582.1, Operation of Energy Storage Equipment, and 
Account 592.2, Maintenance of Energy Storage Equipment.
    87. Finally, the Commission proposes that costs incurred to 
purchase or internally generate power to reenergize an energy storage 
asset after it was first put into service be charged as a current 
operating cost in the appropriate expense accounts for recording such 
costs, including the proposed purchased power account discussed below. 
The Commission seeks comment on its proposals regarding electric plant 
accounts and whether the proposed changes adequately provide for 
recording the cost of new energy storage technologies and the 
development of cost of service rates.
b. Power Purchased and Fuel Supply Expense Accounts
    88. To provide some electrical services, energy storage devices may 
need to maintain a particular state of charge, or as in the case of 
compressed air facilities, may need to maintain some minimum pressure. 
To maintain the desired state of charge or pressure some companies may 
be required to purchase power in retail or wholesale markets to 
energize their energy storage devices and other companies may 
internally generate power. In the NOI, the Commission asked about the 
accounting for the cost of power, fuel and other direct costs incurred 
in energy storage operations. Specifically, the Commission asked about 
accounting for the cost of (1) power purchased and stored for resale; 
(2) power purchased that will not be resold but instead consumed in 
operations during the provisioning of services; (3) power purchased to 
sustain a state of charge; (4) power purchased to initially attain a 
state of charge; and (5) fuel or other direct costs incurred to 
internally generate power.\101\
---------------------------------------------------------------------------

    \101\ NOI, 135 FERC ] 61,240 at PP 38-44.
---------------------------------------------------------------------------

    89. California Storage Alliance and ESA recommend that a new 
expense account entitled ``Power Purchased for Storage Operations'' be 
created to account for items 1-3 above. They indicate that the account 
could also be used to account for item 4 if the costs are expensed as 
incurred; otherwise, they recommend that the costs be capitalized in 
the total cost of the storage resource.\102\ California Storage 
Alliance states that a benefit of having a separate account for power 
purchased for energy storage operations is that energy storage 
operating costs, which are organized on a plant level, can be 
distinguished from traditional utility power purchases and exchanges of 
electricity, which are organized on a company level.
---------------------------------------------------------------------------

    \102\ California Storage Alliance Comments at 32-34; ESA 
Comments at 39-41.
---------------------------------------------------------------------------

    90. As stated above, the Commission proposes that item 4 and 5 
costs of power purchased or internally generated to initially attain a 
state of charge in preparation for service prior to the equipment being 
ready for or placed in service be capitalized as a component cost of 
the equipment. Additionally, we propose that item 5 costs incurred 
later be expensed as incurred and accounted for as an expense of the 
accounting period. Regarding items 1-3, the Commission agrees with 
California Storage Alliance that there is a benefit to having the cost 
of power purchased for energy storage operations reported separate from 
other power purchases. This accounting is expected to enhance the 
transparency of reported cost, which is consistent with the goals of 
this proposed rulemaking. However, we do not agree with California 
Storage Alliance's recommendation that power purchased for energy 
storage operations be accounted for and reported at the individual 
plant level.
    91. California Storage Alliance did not discuss this idea in any 
detail. It is not clear that information is needed to be reported at 
the individual plant level for rate development, transparency, or any 
other purposes. Consequently, rather than proposing that power 
purchased for energy storage operations be accounted for at the 
individual plant level, the Commission proposes that the cost of power 
purchased for energy storage operations be accounted for at the company 
level in new Account 555.1, Power Purchased for Storage Operations. In 
that case, companies with multiple energy storage plant assets will 
record the costs of all power purchased for energy storage operations 
in one account similar to the procedures used to account for power 
purchased for other purposes that are currently recorded in Account 
555, Purchased Power. However, we also propose that companies maintain 
records of costs associated with operation of a particular energy 
storage asset as required by 18 CFR part 125.
    92. Further, the Commission proposes that the instructions to 
Account 555.1 shall be the same as those of Account 555 with an 
additional instruction requiring the cost of power purchased and 
consumed or lost in energy storage operations during the provisioning 
of services be recorded in the new account.\103\
---------------------------------------------------------------------------

    \103\ For example, purchased power may be consumed or lost 
during the conversion process where electric energy is received from 
the grid, stored as another form of energy and later transmitted to 
the grid as electric energy.
---------------------------------------------------------------------------

    93. In regards to item 5 above, California Storage Alliance and ESA 
recommend that the cost of fuel incurred to internally generate power 
for use in energy storage operations be recorded in a new account 
entitled ``Storage Fuel'' and other direct costs incurred in such 
operations be recorded in new accounts entitled ``Operation of Electric 
Storage Equipment'' and ``Maintenance of Electric Storage Equipment.'' 
\104\ California Storage Alliance and ESA do not explain the benefit of 
recording the cost of fuel for this purpose in a new account. While 
this accounting may enhance transparency to some extent, existing fuel 
accounts can adequately support recording the costs of fuel used in 
energy storage operations.
---------------------------------------------------------------------------

    \104\ California Storage Alliance Comments at 34 and 37; ESA 
Comments at 41 and 45.
---------------------------------------------------------------------------

    94. Generating companies currently account for fuel costs in FERC 
accounts by the method of production (i.e., steam, nuclear, hydraulic, 
or other). Recording fuel cost to a new storage fuel account would 
require these companies to calculate the amount of their total fuel 
costs to be allocated to energy storage operations. This data may best 
be reported in a new or existing schedule of the Form Nos. 1 and 1-F 
rather than in a new storage fuel account. California Storage Alliance 
and ESA's

[[Page 40429]]

recommended O&M expense accounts are discussed in the next section.
c. Operation and Maintenance Expense Accounts
    95. As previously indicated there are O&M expenses related to the 
use of these energy storage assets to provide utility services and 
there are no existing O&M expense accounts in the USofA specifically 
dedicated to accounting for the cost of energy storage operations. EEI 
comments that, as it relates to the transmission function, the current 
O&M expense accounts would adequately provide for recording expenses 
associated with operation and maintenance of energy storage 
assets.\105\ The Commission agrees that there are some existing O&M 
expense accounts that can adequately support energy storage-related 
operation and maintenance activities. We also believe current O&M 
expense accounts for the production and distribution functions can 
provide for recording some energy storage-related expenses. However, 
the operations and maintenance of certain energy storage assets may 
differ from conventional assets.\106\ Further, some existing O&M 
expense accounts may not be well suited to record the cost of certain 
activities associated with energy storage operations.\107\ To the 
extent that there are activities and associated costs of energy storage 
operations that are not specifically provided for in the existing O&M 
expense accounts, there is a need for accounts to report the costs.
---------------------------------------------------------------------------

    \105\ EEI Comments at 12. EEI indicated that in instances where 
energy storage assets provide a transmission function, the following 
O&M accounts associated with transmission can be used: Accounts 560, 
561.5, 561.8, 562-564, 566-576.
    \106\ For example, the procedures and practices involving repair 
of a flywheel that serves a transmission function may not be the 
same as the procedures and practices involving repair of a 
transmission line.
    \107\ For example, certain O&M expenses for generator equipment 
used in storage operations that serves a transmission function are 
not well suited for recording in existing transmission O&M expense 
accounts. Such expenses are the type of expenses that would 
typically be incurred in production operations; however, because the 
generator equipment serves a transmission function, the nature of 
the expense is not production. In such cases, the O&M expenses for 
generator equipment should be recorded as a transmission expense 
using the appropriate energy storage equipment transmission O&M 
expense account.
---------------------------------------------------------------------------

    96. California Storage Alliance and ESA recommended that all energy 
storage-related O&M expense costs be recorded in new accounts entitled 
``Operation of Electric Storage Equipment'' and ``Maintenance of 
Electric Storage Equipment.'' However, aggregating all of the O&M costs 
for energy storage into two accounts reduces the transparency of the 
amounts reported, which is contrary to the purpose of the rulemaking. 
Further, because certain costs of energy storage operations can be 
adequately accounted for in the existing O&M expense accounts the costs 
should be reported there in accordance with the instructions of the 
accounts. Consequently, the Commission proposes that companies record 
energy storage-related O&M expenses in the existing O&M expense 
accounts according to the nature of the expense to the extent that the 
account adequately supports recording of the cost.
    97. For energy storage-related O&M expenses that are not 
specifically provided for in the existing O&M expense accounts the 
Commission proposes that such costs be recorded in Account 548.1, 
Operation of Energy Storage Equipment, and Account 553.1, Maintenance 
of Energy Storage Equipment, for energy storage plant classified as 
production; Account 562.1, Operation of Energy Storage Equipment, and 
Account 570.1, Maintenance of Energy Storage Equipment, for energy 
storage plant classified as transmission; and Account 582.1, Operation 
of Energy Storage Equipment, and Account 592.2, Maintenance of Energy 
Storage Equipment, for energy storage plant classified as distribution.
    98. The Commission proposes that the instructions of the accounts 
provide for the inclusion of the cost of labor, materials used and 
expenses incurred in the operation and maintenance, as appropriate, of 
energy storage equipment, to the extent that the costs are not 
appropriately recorded in other O&M expense accounts. Furthermore, we 
propose that Accounts 592, Maintenance of Station Equipment (Major 
only), and 592.1, Maintenance of Structures and Equipment (Nonmajor 
only), be revised such that the accounts do not include O&M expenses 
related to energy storage operations. Additionally, we propose that the 
instructions of these accounts be revised to remove the reference to 
Account 363. The Commission seeks comment on its proposal, including 
whether the operations of certain energy storage assets differ enough 
from conventional assets or maintenance activities to require the 
proposed revisions.
d. No New Revenue Accounts
    99. In the NOI, the Commission asked whether new revenue accounts 
should be created or existing revenue accounts used to account for 
revenue associated with energy storage operations. The Commission also 
asked whether all revenues for energy storage operations should be 
recorded in a single revenue account: Account 456, Other Electric 
Revenues. Most commenters oppose recording all revenues associated with 
energy storage operations in a single account because it would not 
provide sufficient transparency as to the relation of the revenue to a 
particular service provided. Some commenters argue that new revenue 
accounts were needed to account for revenues generated using energy 
storage assets.\108\ These commenters generally argue that the existing 
revenue accounts do not provide sufficient transparency. However, 
commenters opposed to creating new revenue accounts argue that 
production, transmission, and distribution services currently have 
adequate revenue accounts, and energy storage technologies will simply 
comprise a component of those services. These commenters contend that 
revenue derived from the use of energy storage assets will originate 
from the same type of activities associated with revenue derived from 
the use of traditional utility assets.\109\ They argue that the type of 
resource used to provide the service does not change the accounting for 
the associated revenue.
---------------------------------------------------------------------------

    \108\ See, e.g., TAPS Comments at 17-18; BrightSource Comments 
at 7; and Viridity Comments at 4.
    \109\ See, e.g., California Storage Alliance Comments at 34; ESA 
Comments at 42; and FirstEnergy Comments at 5.
---------------------------------------------------------------------------

    100. The Commission agrees with commenters who contend that the 
existing revenue accounts sufficiently provide for accounting for 
revenue associated with using energy storage assets. We also agree that 
revenues associated with the use of energy storage assets will 
originate from the same type of activities associated with revenue 
derived from the use of traditional utility assets. The current revenue 
accounts provide for recording revenue based on sales of electricity 
and other products and services by type of customer, product, or 
service. Revenue derived from the operation of energy storage assets 
will originate from one or more of these items. Commenters recommending 
new accounts have not identified new revenue streams that may require 
different accounting. As such, the Commission does not propose new 
revenue accounts for energy storage. Companies using energy storage 
assets to provide utility service must record revenues associated with 
use of the assets in existing revenue accounts in accordance with the 
instructions of the accounts, as appropriate.

[[Page 40430]]

2. Proposed New and Amended Form Nos. 1, 1-F, and 3-Q Schedules
    101. The Form Nos. 1, 1-F, and 3-Q have schedules that include a 
basic set of financial statements: Comparative Balance Sheet, Statement 
of Income and Retained Earnings, Statement of Cash Flows, and the 
Statement of Comprehensive Income and Hedging Activities. Supporting 
schedules with supplementary information are filed, including revenues 
and the related quantities of products sold or transported; account 
balances for O&M expenses; selected plant cost and operational data; 
and other information. The Form No. 1 provides schedule pages 408-409, 
Pumped Storage Generating Plant Statistics (Large Plants), and pages 
410-411, Generating Plant Statistics (Small Plants) to report, among 
other items, operational information on pumped storage plants. These 
are the only schedules that provide for reporting information on energy 
storage and these schedules do not provide for reporting information on 
new types of energy storage assets such as batteries and flywheels, or 
allow any possibility of treating pumped storage plants as anything 
other than generating assets.
    102. Several commenters responded to the NOI's inquiry about 
whether the Form Nos. 1 and 1-F should be amended to capture data on 
energy storage assets and operations. Commenters recommend that certain 
existing schedules be revised to include energy storage assets and a 
new schedule be created to report operational and statistical data on 
the assets.\110\ The primary difference among the recommendations is 
the amount of detail proposed for inclusion in the new schedule.
---------------------------------------------------------------------------

    \110\ See, e.g., California Storage Alliance Comments at 41; ESA 
Comments at 49; and TAPS Comments at 16.
---------------------------------------------------------------------------

    103. Some commenters recommend that the schedule include all input 
items that are included in the total amount of O&M expenses for an 
energy storage asset, similar to how O&M expenses and plant information 
are currently required to be reported in schedule pages 408-409 of the 
Form No. 1.\111\ In contrast, other commenters propose that the 
information be presented at a higher, aggregated, level with only total 
operation and total maintenance expense for energy storage operations 
reported in the schedule. The Form No. 1 provides schedule pages 408-
409 for reporting detailed plant and O&M expense information on 
generating plants that are considered ``large'' and less detailed plant 
and cost information on generating plants that are considered ``small'' 
in schedule pages 410-411, Generating Plant Statistics (Small Plants). 
According to the instructions of these schedules, the specific schedule 
a utility must use to report its plant statistics and certain 
associated costs is determined by the installed capacity of the unit. 
Generating units with 10,000 kilowatts or more of installed capacity 
will generally report this information in schedule pages 408-409.\112\ 
While this kilowatt threshold may be an appropriate measure of 
information reporting requirements for traditional generating plants, 
it may not be appropriate for new energy storage assets that in many 
instances will be rated below 10,000 kilowatts. Consequently, the 
Commission seeks comment on what would be an appropriate kilowatt 
threshold for requiring utilities to report more detailed plant and 
cost information for energy storage plant.
---------------------------------------------------------------------------

    \111\ See, e.g., California Storage Alliance Comments at 39-42; 
and ESA Comments at 47-50.
    \112\ The 10,000 kW threshold is currently applied to gas-
turbine, internal combustion, nuclear, and conventional hydro and 
pumped storage plants. There is a separate 25,000 kW threshold for 
steam plants (e.g., coal, oil).
---------------------------------------------------------------------------

    104. The Commission proposes to add two new schedules to the Form 
Nos. 1 and 1-F to report statistical and cost data on energy storage 
plant. One schedule will require more detailed information than the 
other to lessen the reporting burden on companies with small energy 
storage operations. We preliminarily propose that 10,000 kilowatts be 
the threshold for determining whether a filer reports more detailed 
information in proposed schedule pages 414-417, Energy Storage 
Operations (Large Plants), or less detailed information in proposed 
schedule pages 419-421, Energy Storage Operations (Small Plants). We 
propose that the following information be reported on pages 414-417 in 
the proposed schedule: (1) Megawatts (MW) purchased, MW delivered to 
the grid to support production, transmission, or distribution 
operations, MW lost during conversion and discharge of energy, and MW 
sold; (2) Account No. 555.1, Power Purchased for Storage Operations; 
(3) cost of fuel used in energy storage operations; (4) revenue from 
the sale of stored energy by revenue account; (5) other energy storage-
related cost incurred; (6) cost of energy storage plant recorded in 
Accounts 101, 103, 106, and 107 by actual or expected functional 
classification; (7) operation and maintenance expenses associated with 
each function; and (8) name and location of energy storage plant, by 
project, and functional classification.
    105. Additionally, we propose that the following information be 
reported on pages 419-421 in the proposed schedule: (1) Cost of plant; 
(2) operation expenses excluding fuel; (3) maintenance expenses; (4) 
cost of fuel used in energy storage operations; (5) Account No. 555.1, 
Power Purchased for Storage Operations; (6) other energy storage-
related cost incurred; and (7) name and location of energy storage 
plant, by project, and functional classification.
    106. Finally, we propose to amend several schedules of the Form 
Nos. 1 and 1-F to include the proposed energy storage plant, purchased 
power and O&M expense accounts discussed above, and schedule page 397, 
Amounts Included in ISO/RTO Settlement Statements, of the Form No. 3-Q 
to include the proposed purchased power account.\113\ The Commission 
seeks public comment on each of the proposals discussed above, 
including whether the proposed changes will provide sufficiently 
transparent information on the activities and costs of new energy 
storage assets and operations.
---------------------------------------------------------------------------

    \113\ See Appendix B Proposed Amendments to Form Nos. 1, 1-F and 
3-Q.
---------------------------------------------------------------------------

III. Information Collection Statement

    107. The collections of information below for this proposed rule 
have been submitted to the Office of Management and Budget (OMB) for 
review under Section 3507(d) of the Paperwork Reduction Act of 
1995.\114\ OMB's regulations require approval of certain information 
collection requirements imposed by agency rule.\115\ The Commission 
solicits comments on its need for this information, whether the 
information will have practical utility, the accuracy of burden and 
cost estimates, ways to enhance the quality, utility, and clarity of 
the information to be collected or retained, and any suggested methods 
for minimizing respondents' burden, including the use of automated 
information techniques.
---------------------------------------------------------------------------

    \114\ See 44 U.S.C. 3507(d).
    \115\ 5 CFR 1320.11 (2011).
---------------------------------------------------------------------------

    Burden Estimate and Information Collection Costs: The additional 
estimated annual public reporting burdens and costs for the 
requirements in this proposed rule are as follows.
---------------------------------------------------------------------------

    \116\ The Form No. 3-Q estimate is one hour since the 
information is already collected and will only require a minor 
separation of costs.
    \117\ The burden in Year 1 is 1,320 hrs. The average annualized 
burden over Years 1-3 is 440 hr. (1,320/3).

[[Page 40431]]



----------------------------------------------------------------------------------------------------------------
                                                                                  Change in the      Estimated
                                   Number of     Change in the    Filings per     total annual      annual cost
        Data collection           respondents      number of    respondent per   hours for this    (at $120/hr.)
                                      (a)          hours per       year (c)      collection (a x  (d x $120/hr.)
                                                  filing (b)                        b x c=d)            ($)
----------------------------------------------------------------------------------------------------------------
Form No. 1....................             210               6               1  1,260...........         151,200
Form No. 1-F..................               5               6               1  30..............           3,600
Form No. 3-Q..................             213         \116\ 1               3  639.............          76,680
FERC-917 [includes 18 CFR                  132              10               1  440 averaged        \117\ 52,800
 35.28 pro forma open-access                                                     over Years 1-3
 transmission tariff (OATT)].                                                    [1320 in Year
                                                                                 1].
FERC-717 [includes OASIS &                 176               2               1  352.............          42,240
 posting data on self-supply
 ancillary services].
FERC-919 [includes `20 percent             155               7               1  1,085...........         130,200
 screen'].
                               ---------------------------------------------------------------------------------
    Total.....................  ..............  ..............  ..............  3,806 (averaged          456,720
                                                                                 over Years 1-3).
----------------------------------------------------------------------------------------------------------------

    Titles: FERC Form No. 1, ``Annual Report of Major Electric 
Utilities, Licensees, and Others;'' FERC Form No. 1-F, ``Annual Report 
for Nonmajor Public Utilities and Licensees;'' FERC Form No. 3-Q, 
``Quarterly Financial Report of Electric Utilities, Licensees and 
Natural Gas Companies;'' FERC-917, ``Non-discriminatory Open Access 
Transmission Tariff,'' FERC-717, ``Standards for Business Practices and 
Communication Protocols for Public Utilities,'' and FERC-919, 
``Electric Rate Schedule Filings: Market Based Rates for Wholesale 
Sales of Electric Energy, Capacity and Ancillary Services by Public 
Utilities.''
    Action: Proposed revisions to information collections.
    OMB Control Nos.: 1902-0021 (FERC Form No. 1); 1902-0029 (FERC Form 
No. 1-F); 1902-0205 (FERC Form No. 3-Q); 1902-0233 (FERC-917), 1902-
0173 (FERC-717); and 1902-0234 (FERC-919).
    Respondents: Public utilities, FERC licensees, and public utility 
transmission providers.
    Frequency of responses: Annually (FERC Form Nos. 1 and 1-F); 
quarterly (FERC Form No. 3-Q); and as needed (FERC-917, FERC-717, and 
FERC-919).
    Necessity of the Information: The proposed rule would amend the 
Commission's regulations to reflect changes occurring in the electric 
industry due to the availability of new energy storage technologies 
that can be used in the provision of large-scale utility operations. 
The addition of these plant accounts, and new and amended reporting 
forms, should enhance transparency and provide detailed information on 
transactions and events affecting public utilities and licensees that 
file reports with the Commission. Without specific instructions and 
accounts for recording and reporting the above transactions and events, 
inconsistent and incomplete accounting and reporting will likely 
result. With regard to FERC-917, FERC-919, and FERC-717 the proposed 
rule would provide increased transparency in the determination of 
Regulation and Frequency Response requirements, historical ancillary 
service information, and ancillary service capacity in order to ensure 
that rates for that service remain just, reasonable, and not unduly 
discriminatory.
    Internal Review: The Commission has reviewed the requirements 
pertaining to the USofA and the reports it prescribes and determined 
that the proposed amendments are necessary because the Commission needs 
to establish uniform accounting and reporting requirements for the 
costs of utility assets and expenses incurred for providing services as 
part of a utility's operations. The Commission has reviewed the 
requirements associated with the OATT, OASIS, and market power analysis 
and determined they are necessary to increase transparency and ensure 
that rates remain just, reasonable, and not unduly discriminatory.
    108. These requirements conform to the Commission's need for 
efficient information collection, communication, and management within 
the energy industry. The Commission has assured itself, through 
internal review, that there is specific, objective support for the 
burden estimates associated with the information collection 
requirements.
    109. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director], email: 
DataClearance@ferc.gov, Phone (202) 502-8663, fax: (202) 273-0873.
    Comments on the collections of information and associated burden 
estimates in the proposed rule should be sent to the Commission in this 
docket and may also be sent to the Office of Information and Regulatory 
Affairs, Office of Management and Budget, Washington, DC 20503 
[Attention: Desk Officer for the Federal Energy Regulatory Commission]. 
For security reasons, comments to OMB should be submitted by email to: 
oira_submission@omb.eop.gov. Please refer to OMB Control Nos. 1902-
0021 (FERC Form No. 1); 1902-0029 (FERC Form No. 1-F); 1902-0205 (FERC 
Form No. 3-Q); 1902-0233 (FERC-917), 1902-0173 (FERC-717); and 1902-
0234 (FERC-919) and Docket Number RM11-24.

IV. Environmental Analysis

    110. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\118\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Final Rule under 
section 380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale subject to the Commission's 
jurisdiction, plus the classification, practices, contracts, and 
regulations that affect rates, charges, classifications, and 
services.\119\
---------------------------------------------------------------------------

    \118\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & 
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \119\ 18 CFR 380.4(a)(15) (2011).

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[[Page 40432]]

V. Regulatory Flexibility Act

    111. The Regulatory Flexibility Act of 1980 (RFA) \120\ generally 
requires a description and analysis of proposed rules that will have 
significant economic impact on a substantial number of small entities. 
The RFA mandates consideration of regulatory alternatives that 
accomplish the stated objectives of a proposed rule and that minimize 
any significant economic impact on a substantial number of small 
entities. The Small Business Administration's (SBA's) Office of Size 
Standards develops the numerical definition of a small business.\121\ 
The SBA has established a size standard for electric utilities, stating 
that a firm is small if, including its affiliates, it is primarily 
engaged in the transmission, generation and/or distribution of electric 
energy for sale and its total electric output for the preceding twelve 
months did not exceed four million megawatt hours.\122\ Most companies 
regulated by the Commission do not fall within the RFA's definition of 
a small entity.\123\ The proposed rule applies exclusively to public 
utilities that own, control, or operate facilities for transmitting 
electric energy in interstate commerce and not electric utilities per 
se. Based on the filers of the annual FERC Form No. 1 and Form No. 1-F, 
as well as the number of companies that have obtained waivers, we 
estimate that 6.8 percent of the filers affected by this proposed rule 
are ``small.'' The Commission believes this rule will not have a 
significant economic impact on a substantial number of small entities, 
and therefore no regulatory flexibility analysis is required.
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    \120\ 5 U.S.C. 601-612.
    \121\ 13 CFR 121.101 (2011).
    \122\ 13 CFR 121.201, Sector 22, Utilities.
    \123\ See 5 U.S.C. 601(3) citing to section 3 of the Small 
Business Act, 15 U.S.C. 632. Section 3 of the Small Business Act 
defines a ``small-business concern'' as a business which is 
independently owned and operated and which is not dominant in its 
field of operation. The Small Business Size Standards component of 
the North American Industry Classification System defines a small 
electric utility as one that, including its affiliates, is primarily 
engaged in generation, transmission, and/or distribution of electric 
energy for sale and whose total electric output for the preceding 
fiscal years did not exceed 4 million MWh. 13 CFR 121.201 (2011).
---------------------------------------------------------------------------

VI. Comment Procedures

    112. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this notice to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due 60 days after 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.
    113. 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.
    114. Commenters that are not able to file comments electronically 
must send an original of their comments to: Federal Energy Regulatory 
Commission, Secretary of the Commission, 888 First Street NE., 
Washington, DC 20426.
    115. 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.

VII. Document Availability

    116. 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 the Commission's Home Page (http://www.ferc.gov) and 
in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, 
Washington DC 20426.
    117. From the Commission'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.
    118. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from the Commission's Online 
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

List of Subjects in 18 CFR Parts 35, 37, and 101

    Electric power rates; Electric utilities.

    By direction of the Commission. Commissioner Clark voting 
present.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

    In consideration of the foregoing, the Commission proposes to amend 
Parts 35, 37, and 101, Chapter I, Title 18, Code of Federal 
Regulations, as follows.

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. Sec.  9701; 
42 U.S.C. 7101-7352.

    2. Amend Sec.  35.28 by adding a new paragraph (c)(1)(viii) as 
follows.


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (c)(1)(viii) Each public utility's open access transmission tariff, 
at Schedule 3--Regulation and Frequency Response Service, must include 
provisions explaining how it will determine its Regulation and 
Frequency Response reserve requirements. These provisions must take 
into account speed and accuracy of regulation resources and include a 
description of how the public utility transmission provider would make 
adjustments to the capacity requirement when a customer opts to 
purchase from third-parties or self-supply its requirements using 
resources with speed and accuracy characteristics that differ from the 
set of resources otherwise being used for Regulation and Frequency 
Response Service.
* * * * *
    3. Amend Sec.  35.37 as follows:
    a. Paragraph (c)(1) is revised.
    b. New paragraph (c)(5) is added.


Sec.  35.37  Market power analysis required.

* * * * *
    (c)(1) There will be a rebuttable presumption that a Seller lacks 
horizontal market power with respect to sales of energy, capacity, 
energy imbalance service, and generation imbalance service if it passes 
two indicative market power screens: a pivotal supplier analysis based 
on annual peak demand of the relevant market, and a market share 
analysis applied on a seasonal basis. There will be a rebuttable 
presumption that a seller possesses horizontal market power with 
respect to sales of energy, capacity, energy imbalance service, and 
generation imbalance service if it fails either screen.
* * * * *
    (c)(5) There will be a rebuttable presumption that a Seller of 
Operating

[[Page 40433]]

Reserve--Spinning, Operating Reserve--Supplemental, Reactive Supply and 
Voltage Control, or Regulation and Frequency Response services lacks 
horizontal market power with respect to sales of the ancillary service 
in question if the amount of capacity in MWs (or, as applicable, MVARs) 
that it can dedicate to providing the ancillary service in the relevant 
geographic market, taking into account any reported historical 
locational requirements, is no more than 20 percent of the relevant 
reported aggregate requirement for that ancillary service as reported 
pursuant to Sec.  37.6(k) of the Commission's Regulations.
* * * * *
    4. Amend Sec.  35.38 as follows:
    a. Paragraph (a) is revised.
    b. Paragraph (b) is revised.
    c. New paragraph (c) is added.


Sec.  35.38  Mitigation.

    (a) A Seller that has been found to have market power in generation 
or ancillary services, or that is presumed to have horizontal market 
power in generation or ancillary services by virtue of failing or 
foregoing the relevant market power screens, as described in 35.37(c), 
may adopt the default mitigation detailed in paragraph (b) of this 
section for sales of energy or capacity or paragraph (c) of this 
section for sales of ancillary services or may propose mitigation 
tailored to its own particular circumstances to eliminate its ability 
to exercise market power. Mitigation will apply only to the market(s) 
in which the Seller is found, or presumed, to have market power.
    (b) Default mitigation for sales of energy or capacity consists of 
three distinct products:
* * * * *
    (c) Default mitigation for sales of ancillary services consists of: 
(1) A cost-based cap based on the relevant OATT ancillary service rate 
of the purchasing public utility transmission operator; (2) a cost-
based cap based on the highest relevant public utility OATT ancillary 
service rate in the proposed trading area; or (3) the results of a 
competitive solicitation that meets the Commission's requirements for 
transparency, definition, evaluation, oversight, and adequate seller 
interest to ensure competitiveness.

PART 37--OPEN ACCESS SAME-TIME INFORMATION SYSTEMS

    5. The authority citation for Part 37 continues to read as follows:

    Authority: 16 U.S.C. 791-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

    6. Amend Sec.  37.6 by adding a new paragraph (k) as follows.


Sec.  37.6  Information to be posted on the OASIS.

* * * * *
    (k) Posting data related to historical ancillary service 
requirements. The Transmission Provider must post on OASIS information 
as to the aggregate amount (MW or MVAR, as applicable) of Operating 
Reserve--Spinning, Operating Reserve--Supplemental, Reactive Supply and 
Voltage Control, and Regulation and Frequency Response services that it 
has historically required in order to serve its long-term firm 
obligations, including any geographic limitations it may face in 
meeting such ancillary service requirements.

PART 101--UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC 
UTILITIES AND LICENSEES SUBJECT TO THE PROVISIONS OF THE FEDERAL 
POWER ACT

    7. The authority citation for Part 101 continues to read as 
follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352, 7651-7651o.

    8. In Part 101, Electric Plant Chart of Accounts, Account 348 is 
added to the list:

Electric Plant Chart of Accounts

* * * * *
2. PRODUCTION PLANT
* * * * *
D. OTHER PRODUCTION
* * * * *
348 Energy Storage Equipment--Production
* * * * *
    9. In Part 101, Electric Plant Accounts, Account 351, the name of 
the account is amended and instructions are added to read as follows:

Electric Plant Accounts

* * * * *

351 Energy Storage Equipment--Transmission

    A. This account shall include the cost installed of energy storage 
equipment used to store energy for load managing purposes. Where energy 
storage equipment can perform more than one function or purpose, the 
cost of the equipment shall be allocated among production, 
transmission, and distribution plant based on the services provided by 
the asset and the allocation of the asset's cost through rates approved 
by a relevant regulatory agency. Reallocation of the cost of equipment 
recorded in this account shall be in accordance with Electric Plant 
Instruction No. 12, Transfers of Property.
    B. Labor costs and power purchase and generation costs incurred to 
install and energize the equipment are includible on the first 
installation only. The cost of removing, relocating and resetting 
energy storage equipment shall not be charged to this account but to 
Account 562.1, Operation of Energy Storage Equipment, and Account 
570.1, Maintenance of Energy Storage Equipment, as appropriate.
    C. The records supporting this account shall show, by months, the 
function(s) each energy storage asset supports or performs.
ITEMS
1. Batteries/Chemical
2. Compressed Air
3. Flywheels
4. Superconducting Magnetic Storage
5. Thermal

    10. In Part 101, Electric Plant Accounts, Account 363, the name of 
the account and the instructions are amended and added to read as 
follows:

Electric Plant Accounts

* * * * *

363 Energy Storage Equipment--Distribution

    A. This account shall include the cost installed of energy storage 
equipment used to store energy for load managing purposes. Where energy 
storage equipment can perform more than one function or purpose, the 
cost of the equipment shall be allocated among production, 
transmission, and distribution plant based on the services provided by 
the asset and the allocation of the asset's cost through rates approved 
by a relevant regulatory agency. Reallocation of the cost of equipment 
recorded in this account shall be in accordance with Electric Plant 
Instruction No. 12, Transfers of Property.
    B. Labor costs and power purchase and generation costs incurred to 
install and energize the equipment are includible on the first 
installation only. The cost of removing, relocating and resetting 
energy storage equipment shall not be charged to this account but to 
Account 582.1, Operation of Energy Storage Equipment, and Account 
592.2, Maintenance of Energy Storage Equipment, as appropriate.
    C. The records supporting this account shall show, by months, the 
function(s) each energy storage asset supports or performs.

[[Page 40434]]

ITEMS
1. Batteries/Chemical
2. Compressed Air
3. Flywheels
4. Superconducting Magnetic Storage
5. Thermal

    11. In Part 101, Electric Plant Accounts, new primary plant account 
348 is added to read as follows:

Electric Plant Accounts

* * * * *

348 Energy Storage Equipment--Production

    A. This account shall include the cost installed of energy storage 
equipment used to store energy for load managing purposes. Where energy 
storage equipment can perform more than one function or purpose, the 
cost of the equipment shall be allocated among production, 
transmission, and distribution plant based on the services provided by 
the asset and the allocation of the asset's cost through rates approved 
by a relevant regulatory agency. Reallocation of the cost of equipment 
recorded in this account shall be in accordance with Electric Plant 
Instruction No. 12, Transfers of Property.
    B. Labor costs and power purchase and generation costs incurred to 
install and energize the equipment are includible on the first 
installation only. The cost of removing, relocating and resetting 
energy storage equipment shall not be charged to this account but to 
Account 548.1, Operation of Energy Storage Equipment, and Account 
553.1, Maintenance of Energy Storage Equipment, as appropriate.
    C. The records supporting this account shall show, by months, the 
function(s) each energy storage asset supports or performs.
ITEMS
1. Batteries/Chemical
2. Compressed Air
3. Flywheels
4. Superconducting Magnetic Storage
5. Thermal


    Note: The cost of pumped storage hydroelectric plant shall be 
charged to hydraulic production plant. These are examples of items 
includible in this account. This list is not exhaustive.


    12. In Part 101, Operation and Maintenance Expense Chart of 
Accounts, Accounts 548.1, 553.1, 555.1, 562.1, 570.1, 582.1, and 592.2 
are added to the list:

Operation and Maintenance Expense Chart of Accounts

* * * * *
1. POWER PRODUCTION EXPENSES
* * * * *
D. OTHER POWER GENERATION
* * * * *
Operation
* * * * *
548.1 Operation of Energy Storage Equipment
* * * * *
Maintenance
553.1 Maintenance of Energy Storage Equipment
* * * * *
E. OTHER POWER SUPPLY EXPENSES
* * * * *
555.1 Power Purchased for Storage Operations
* * * * *
2. TRANSMISSION EXPENSES
* * * * *
Operation
* * * * *
562.1 Operation of Energy Storage Equipment
* * * * *
Maintenance
* * * * *
570.1 Maintenance of Energy Storage Equipment
* * * * *
4. DISTRIBUTION EXPENSES
* * * * *
Operation
* * * * *
582.1 Operation of Energy Storage Equipment
* * * * *
Maintenance
* * * * *
592.2 Maintenance of Energy Storage Equipment
    13. In Part 101, Operation and Maintenance Expense Accounts, new 
operation expense account 548.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

548.1 Operation of Energy Storage Equipment

    This account shall include the cost of labor, materials used and 
expenses incurred in the operation of energy storage equipment 
includible in Account 348, Energy Storage Equipment-Production, which 
are not specifically provided for or are readily assignable to other 
production operation expense accounts.
    14. In Part 101, Operation and Maintenance Expense Accounts, new 
maintenance expense account 553.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

553.1 Maintenance of Energy Storage Equipment

    This account shall include the cost of labor, materials used and 
expenses incurred in the maintenance of energy storage equipment 
includible in Account 348, Energy Storage Equipment-Production, which 
are not specifically provided for or are readily assignable to other 
production maintenance expense accounts.
    15. In Part 101, Operation and Maintenance Expense Accounts, new 
power supply expense account 555.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

555.1 Power Purchased for Storage Operations

    A. This account shall include the cost at point of receipt by the 
utility of electricity purchased for use in storage operations, 
including power purchased and consumed or lost in energy storage 
operations during the provision of services, including but not limited 
to energy purchased and stored for resale. It shall also include but 
not be limited to net settlements for exchange of electricity or power, 
such as economy energy, off-peak energy for on-peak energy, and 
spinning reserve capacity. In addition, the account shall include the 
net settlements for transactions under pooling or interconnection 
agreements wherein there is a balancing of debits and credits for 
energy, capacity, and possibly other factors. Distinct purchases and 
sales shall not be recorded as exchanges and net amounts only recorded 
merely because debit and credit amounts are combined in the voucher 
settlement.
    B. The records supporting this account shall show, by months, the 
kilowatt hours and prices thereof under each purchase contract and the 
charges and credits under each exchange or power pooling contract.

[[Page 40435]]

    16. In Part 101, Operation and Maintenance Expense Accounts, new 
operation expense account 562.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

562.1 Operation of Energy Storage Equipment

    This account shall include the cost of labor, materials used and 
expenses incurred in the operation of energy storage equipment 
includible in Account 351, Energy Storage Equipment-Transmission, which 
are not specifically provided for or are readily assignable to other 
transmission operation expense accounts.
    17. In Part 101, Operation and Maintenance Expense Accounts, new 
maintenance expense account 570.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

570.1 Maintenance of Energy Storage Equipment

    This account shall include the cost of labor, materials used and 
expenses incurred in the maintenance of energy storage equipment 
includible in Account 351, Energy Storage Equipment-Transmission, which 
are not specifically provided for or are readily assignable to other 
transmission maintenance expense accounts.
    18. In Part 101, Operation and Maintenance Expense Accounts, new 
operation expense account 582.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

582.1 Operation of Energy Storage Equipment

    This account shall include the cost of labor, materials used and 
expenses incurred in the operation of energy storage equipment 
includible in Account 363, Energy Storage Equipment-Distribution, which 
are not specifically provided for or are readily assignable to other 
distribution operation expense accounts.
    19. In Part 101, Operation and Maintenance Expense Accounts, new 
maintenance expense account 592.2 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

592.2 Maintenance of Energy Storage Equipment

    This account shall include the cost of labor, materials used and 
expenses incurred in the maintenance of energy storage equipment 
includible in Account 363, Energy Storage Equipment-Distribution, which 
are not specifically provided for or are readily assignable to other 
distribution maintenance expense accounts.

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


   Appendix A: List of Short Names of Commenters on the Federal Energy
  Regulatory Commission's Notice of Inquiry on Third-Party Provision of
 Ancillary Services; Accounting and Financial Reporting for New Electric
         Storage Technologies--Docket No. RM11-24-000, June 2011
------------------------------------------------------------------------
         Short Name or Acronym                      Commenter
------------------------------------------------------------------------
A123...................................  A123 Systems, Inc.
AEP....................................  American Electric Power Service
                                          Corporation.
AES Energy Storage.....................  AES Energy Storage.
APPA...................................  American Public Power
                                          Association.
Apparent Inc...........................  Apparent Inc.
Aquion Energy, Inc.....................  Aquion Energy, Inc.
AWEA...................................  American Wind Energy
                                          Association.
Beacon Power Corporation...............  Beacon Power Corporation.
Bonneville.............................  Bonneville Power
                                          Administration.
BrightSource...........................  BrightSource Energy, Inc.
Business Council for Sustainable Energy  Business Council for
                                          Sustainable Energy.
California PUC.........................  California Public Utilities
                                          Commission.
California Storage Alliance............  California Energy Storage
                                          Alliance.
CAREBS.................................  Coalition to Advance Renewable
                                          Energy Through Bulk Storage.
EEI....................................  Edison Electric Institute.
Electricity Consumers..................  Electricity Consumers Resource
                                          Council.
ENBALA.................................  Enbala Power Networks.
Environmental Defense Fund.............  Environmental Defense Fund.
EPSA...................................  Electric Power Supply
                                          Association.
ESA....................................  Electricity Storage
                                          Association.
FirstEnergy............................  The Cleveland Electric
                                          Illuminating Company, Jersey
                                          Central Power & Light Company,
                                          Metropolitan Edison Company,
                                          Ohio Edison Company,
                                          Pennsylvania Electric Company,
                                          Pennsylvania Power Company,
                                          The Toledo Edison Company,
                                          Monongahela Power Company, The
                                          Potomac Edison Company, West
                                          Penn Power Company,
                                          FirstEnergy Solutions Corp.,
                                          American Transmission Systems,
                                          Incorporated and Trans-
                                          Allegheny Interstate Line
                                          Company.
FriiPwr................................  FriiPwr USA.
Hydro Association......................  National Hydropower
                                          Association.
IID....................................  Imperial Irrigation District.
Mark Lively............................  Mark B. Lively.
National Grid..........................  National Grid USA.
National Park Service..................  National Park Service.
NaturEner..............................  NaturEner USA, LLC.
NextStep...............................  NextStep Electric, LLC.
NGK/TI.................................  NGK Insulators, Ltd and
                                          Technology Insights.
NGSA...................................  Natural Gas Supply Association.

[[Page 40436]]

 
Northwest Group........................  Avista Corporation, Bonneville
                                          Power Administration, Chelan
                                          County PUD, Clark Public
                                          Utilities, Cowlitz County PUD,
                                          Idaho Power Company,
                                          NorthWestern Energy,
                                          PacifiCorp, Public Power
                                          Council, Public Utility
                                          District No. 2 of Grant
                                          County, and Puget Sound
                                          Energy, Inc.
Portland General.......................  Portland General Electric
                                          Company.
Powerex................................  Powerex Corporation.
PPL Companies..........................  PPL EnergyPlus, LLC and PPL
                                          Montana, LLC.
Prudent Energy.........................  Prudent Energy Corporation.
Public Interest Organizations..........  Center for Rural Affairs, Clean
                                          Wisconsin, Climate + Energy
                                          Project, Conservation Law
                                          Foundation, Environment
                                          Northeast, Fresh Energy, Land
                                          Trust Alliance, Natural
                                          Resources Defense Council,
                                          Pace Energy and Climate
                                          Center, Project for
                                          Sustainable FERC Energy
                                          Policy, Sierra Club and Union
                                          of Concerned Scientists.
Riverbank..............................  Riverbank Power Corporation.
Saft...................................  Saft America, Inc.
SDG&E..................................  San Diego Gas & Electric
                                          Company.
Shell Energy...........................  Shell Energy North America
                                          (US), L.P.
Solar Energy Association...............  Solar Energy Industries
                                          Association.
SolarReserve...........................  SolarReserve LLC.
Southern California Edison.............  Southern California Edison
                                          Company.
Starwood...............................  Starwood Energy Group Global,
                                          LLC.
Steffes................................  Steffes Corporation.
TAPS...................................  Transmission Access Policy
                                          Study Group.
Viridity...............................  Viridity Energy Inc.
WADE/Wartsila..........................  WADE USA and Wartsila North
                                          America.
WSPP...................................  WSPP, Inc.
Xtreme.................................  Xtreme Power.
------------------------------------------------------------------------


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

Appendix B--New and Amended Form 1/1F/3Q Pages

BILLING CODE 6717-01-P

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[FR Doc. 2012-15763 Filed 7-6-12; 8:45 am]
BILLING CODE 6717-01-C