[Federal Register Volume 77, Number 131 (Monday, July 9, 2012)]
[Proposed Rules]
[Pages 40414-40458]
From the Federal Register Online via the Government Publishing 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
[[Page 40414]]
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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.
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\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.
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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.
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\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)).
---------------------------------------------------------------------------
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.
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\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.
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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.
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\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.
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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.
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\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\
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\69\ NOI, 135 FERC ] 61,240 at P 25.
\70\ Id.
\71\ Id.
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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\
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\72\ Electricity Consumers Comments at 8.
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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\
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\73\ TAPS Comments at 13.
\74\ Id. at 12.
\75\ APPA Comments at 7.
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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.
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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\
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\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.
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\80\ SolarReserve Comments at 5.
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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\
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\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.
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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\
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\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.
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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.
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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\
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\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.
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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.
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\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.
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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.
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\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.
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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).
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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\
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\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\
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\100\ These proposed energy storage O&M expense accounts are
discussed in more detail below at section 1(c).
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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\
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\101\ NOI, 135 FERC ] 61,240 at PP 38-44.
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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.
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\102\ California Storage Alliance Comments at 32-34; ESA
Comments at 39-41.
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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\
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\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.
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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.
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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.
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\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.
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\113\ See Appendix B Proposed Amendments to Form Nos. 1, 1-F and
3-Q.
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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.
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\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:
[email protected], 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:
[email protected]. 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\
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\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).
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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
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
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
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[FR Doc. 2012-15763 Filed 7-6-12; 8:45 am]
BILLING CODE 6717-01-C