Document ID: FERC-2013-1038-0001
Agency: ferc
Document Type: Rule
Title: Third-Party Provision of Ancillary Services: Accounting and Financial Reporting for New Electric Storage Technologies
Posted Date: 2013-07-30T04:00Z

[Federal Register Volume 78, Number 146 (Tuesday, July 30, 2013)]
[Rules and Regulations]
[Pages 46177-46237]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-17746]

[[Page 46177]]

Vol. 78

Tuesday,

No. 146

July 30, 2013

Part V

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Parts 35 and 101

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

  Federal Register / Vol. 78, No. 146 / Tuesday, July 30, 2013 / Rules 
and Regulations  

[[Page 46178]]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 35 and 101

[Docket Nos. RM11-24-000 and AD10-13-000; Order No. 784]

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

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
revising its regulations to foster competition and transparency in 
ancillary services markets. The Commission is revising 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 is revising its regulations to reflect reforms to its Avista 
policy governing the sale of ancillary services at market-based rates 
to public utility transmission providers. The Commission is also 
requiring each public utility transmission provider to add to its OATT 
Schedule 3 a statement that it will take into account the speed and 
accuracy of regulation resources in its determination of reserve 
requirements for Regulation and Frequency Response service, including 
as it reviews whether a self-supplying customer has made ``alternative 
comparable arrangements'' as required by the Schedule. The final rule 
also requires each public utility transmission provider to post certain 
Area Control Error data as described in the final rule. Finally, the 
Commission is revising 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.

DATES: This rule is effective November 27, 2013.

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:
Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, 
John R. Norris, Cheryl A. LaFleur, and Tony Clark.

Order No. 784

Final Rule

Issued July 18, 2013.

Table of Contents

 
                                                               Paragraph
                                                                  No.
 
I. Background...............................................           6
II. Discussion..............................................          12
    A. The Avista Policy....................................          12
        1. Use of Market Power Analyses.....................          17
            a. Reliance on Existing Indicative Screens......          20
                i. Application to Imbalance Ancillary                 22
                 Services...................................
                ii. Application to Other Ancillary Services.          43
            b. Optional Market Power Screen.................          62
        2. Alternative Mitigation...........................          75
            a. Use of Price Caps............................          76
                i. Single OATT Rate Cap Option..............          77
                ii. Regional OATT Rate Cap Option...........          86
            b. Competitive Solicitations....................          95
    B. Resource Speed and Accuracy in Determination of               102
     Regulation and Frequency Response Reserve Requirements.
    C. Accounting and Reporting for Energy Storage                   122
     Operations.............................................
    D. Other Issues.........................................         188
III. Summary of Compliance and Implementation...............         201
IV. Information Collection Statement........................         207
V. Environmental Analysis...................................         208
VI. Regulatory Flexibility Act..............................         209
VII. Document Availability..................................         210
 

    1. The Federal Energy Regulatory Commission (Commission) is 
revising its regulations to enhance competition and transparency in 
ancillary services markets. The Commission is revising 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 is revising Part 35 of its regulations to reflect reforms to 
its Avista Corp.\1\ policy governing the sale of ancillary services at 
market-based rates to public utility transmission providers. The 
Commission is also requiring each public utility transmission provider 
to add to its OATT Schedule 3 a statement that it will take into 
account the speed and accuracy of regulation resources in its 
determination of reserve requirements for Regulation and Frequency 
Response service, including as it reviews whether a self-supplying 
customer has made ``alternative comparable arrangements'' as required

[[Page 46179]]

by the Schedule. Each public utility transmission provider is also 
required to post certain Area Control Error data on the open access 
same-time information system (OASIS). Finally, the Commission is 
revising the accounting and reporting requirements under its Uniform 
System of Accounts for public utilities and licensees (USofA) \2\ and 
its forms, statements, and reports, contained in FERC Form No. 1 (Form 
No. 1), Annual Report of Major Electric Utilities, Licensees and 
Others,\3\ FERC Form No. 1-F (Form No. 1-F), Annual Report for Nonmajor 
Public Utilities and Licensees,\4\ and FERC Form No. 3-Q (Form No. 3-
Q), Quarterly Financial Report of Electric Utilities, Licensees, and 
Natural Gas Companies,\5\ 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 87 FERC ] 61,223 (Avista), order on reh'g, 89 FERC ] 
61,136 (1999).
    \2\ Uniform System of Accounts Prescribed for Public Utilities 
and Licensees Subject to the Provisions of the Federal Power Act, 18 
CFR Part 101 (2012).
    \3\ 18 CFR 141.1 (2012).
    \4\ 18 CFR 141.2 (2012).
    \5\ 18 CFR 141.400 (2012).
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    2. First, the Commission reforms the Avista policy governing sales 
of certain ancillary services to a public utility purchasing the 
ancillary service to satisfy its own OATT requirements to offer 
ancillary services to its own customers. As noted in the Notice of 
Proposed Rulemaking,\6\ there is a growing need for ancillary services 
to support grid functions in the face of potential changes in the 
portfolio of generation resources and a growing interest of 
transmission providers to have flexibility in meeting ancillary 
services needs.\7\ There is also interest in third-party provision of 
ancillary services and that interest may be unnecessarily frustrated by 
the Avista policy. Comments to the NOPR's proposal to reconsider the 
Avista restrictions generally supported these concepts. As such, and as 
discussed further below, we conclude that elements of our existing 
market-based rate regulations can be modified in a manner that 
continues to limit the exercise of market power, while also enhancing 
the ability of third parties to compete for the sale of certain 
ancillary services.
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    \6\ Third-Party Provision of Ancillary Services; Accounting and 
Financial Reporting for New Electric Storage Technologies, Notice of 
Proposed Rulemaking, FERC Stats. & Regs. ] 32,690 (2012) (NOPR).
    \7\ Integration of Variable Energy Resources, Order No. 764, 
FERC Stats. & Regs. ] 32,331, order on reh'g, Order No. 764-A, 141 
FERC ] 61,232 (2012); and Demand Response Compensation in Organized 
Wholesale Energy Markets, Order No. 745, FERC Stats. & Regs. ] 
31,322, order on reh'g, Order No. 745-A, 137 FERC ] 61,215 (2011).
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    3. Second, we adopt reforms to provide greater transparency with 
regard to reserve requirements for Regulation and Frequency Response. 
Under the requirements of the pro forma OATT, transmission customers 
may either purchase Regulation and Frequency Response service at cost-
based rates from the public utility transmission provider pursuant to 
its OATT or self-supply the service, including through purchases from 
third-parties.\8\ With regard to the notion of self-supply, the pro 
forma OATT Schedule 3 merely states that the transmission customer must 
make alternative comparable arrangements to satisfy is Regulation and 
Frequency Response Service obligation. In particular, Schedule 3 
provides no discussion of the meaning of the term ``comparable'' as it 
relates to reliance on resources with dispatch speed and accuracy 
characteristics that may differ from those used by the public utility 
transmission provider. Because the system must be operated reliably at 
all times, the customer may not decline the transmission provider's 
offer of ancillary services unless it demonstrates that it has acquired 
comparable services from another source.\9\ In order to clarify the 
role of resource speed and accuracy in the determination of alternative 
comparable arrangements, in this Final Rule the Commission requires 
each public utility transmission provider to add to its OATT Schedule 3 
a statement that it will take into account the speed and accuracy of 
regulation resources in its determination of reserve requirements for 
Regulation and Frequency Response service, including as it reviews 
whether a self-supplying customer has made ``alternative comparable 
arrangements'' as required by the Schedule. This statement will also 
acknowledge that, upon request by the self-supplying customer, the 
public utility transmission provider will share with the customer its 
reasoning and any related data used to make the determination of 
whether the customer has made ``alternative comparable arrangements.'' 
To aid the transmission customer's ability to make an ``apples-to-
apples'' comparison of regulation resources, the final rule also 
requires each public utility transmission provider to post on OASIS 
historical one-minute and ten-minute Area Control Error data as 
described in the final rule for the most recent calendar year, and 
update this posting once per year.
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    \8\ 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 31,716 
(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); pro forma OATT, Original Sheet Nos. 20-21 
and Schedule 3, Original Sheet No. 113.
    \9\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,716.
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    4. With this information, a transmission customer will be in a 
position to demonstrate to the public utility transmission provider 
that the resource(s) it selects for self-supply are comparable to those 
of the public utility transmission provider. As such, these reforms are 
necessary to address the potential for undue discrimination against 
transmission customers choosing to self-supply Regulation and Frequency 
Response, including through purchases from third-parties. Acknowledging 
the speed and accuracy of the resources used to provide this service 
will help to ensure that self-supply requirements of the public utility 
transmission provider do not unduly discriminate by requiring customers 
to procure a different amount of regulation reserves than the 
particular speed and accuracy characteristics of the resources in 
question justify (i.e., to be comparable, a customer self-supply 
arrangement that relies on slower, less accurate resources than those 
of the public utility transmission provider should probably involve a 
larger reserve requirement than would a purchase from the transmission 
provider, and vice versa). Moreover, as the Commission has previously 
stated, because most generation-based ancillary services can be 
provided by many of the generators connected to the transmission 
system, some customers may be able to provide or procure such services 
more economically than the transmission provider can.\10\
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    \10\ Id. at 31,718. We note that customers could conceivably 
procure such services more economically either by paying much less 
per unit for a larger amount of slower, less accurate resources, or 
by paying somewhat more per unit for a smaller amount of faster, 
more accurate resources.
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    5. Finally, we adopt reforms to our accounting and reporting 
regulations to add new electric plant and operation and maintenance 
(O&M) expense accounts for energy storage devices. These reforms are 
necessary to accommodate the increasing availability of these new 
resources for use in public utility operations. These reforms are also 
necessary to ensure that the activities and costs of new energy

[[Page 46180]]

storage operations are sufficiently transparent to allow effective 
oversight.

Background

    6. The Commission has taken numerous steps 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.\11\ With regard to 
ancillary services, the Commission in Order No. 888 delineated two 
categories of ancillary services: Those that the transmission provider 
is required to provide to all of its basic transmission customers \12\ 
and those that the transmission provider is only required to offer to 
provide to transmission customers serving load in the transmission 
provider's control area.\13\ With respect to the second category the 
Commission reasoned that the transmission provider is not always 
uniquely qualified to provide the services and customers may be able to 
more cost-effectively self-supply them or procure them from other 
entities. The Commission 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.\14\ Later, in Ocean Vista 
Power Generation, L.L.C.,\15\ 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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    \11\ See, e.g., Order No. 888, FERC Stats. & Regs. ] 31,036, at 
31,781; 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), cert. denied 
sub nom. Pub. Citizen, Inc. v. FERC, 133 S. Ct. 26 (2012); 
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).
    \12\ The first category consists of Scheduling, System Control 
and Dispatch service and Reactive Supply and Voltage Control from 
Generation Sources service.
    \13\ The second category consists of Regulation and Frequency 
Response service, Energy Imbalance service, Operating Reserve-
Spinning service, and Operating Reserve-Supplemental service. Order 
No. 890 later added an additional OATT ancillary service to this 
category: Generator Imbalance service. See Order No. 890, FERC 
Stats. & Regs. ] 31,241 at P 85.
    \14\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,720-21.
    \15\ 82 FERC ] 61,114, at 61,406-07 (1998) (Ocean Vista).
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    7. The Commission subsequently acknowledged in Avista \16\ 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 at market-based rates with 
certain restrictions.\17\ 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 a regional transmission organization 
(RTO) or an independent system operator (ISO), which has no ability to 
self-supply ancillary services but instead depends on third parties; 
\18\ (2) to address affiliate abuse concerns, sales to a traditional, 
franchised public utility affiliated with the third-party supplier, or 
sales where the underlying transmission service is on the system of the 
public utility affiliated with the third-party supplier; 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.\19\ Therefore, the Commission's Avista policy has allowed 
third-party suppliers to sell certain ancillary services at market-
based rates without showing a lack of market power, except under these 
three circumstances.
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    \16\ Avista, 87 FERC at 61,882.
    \17\ 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.
    \18\ 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.
    \19\ Avista, 87 FERC ] 61,223 at n.12.
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    8. In its ongoing effort to enhance competitive markets as a means 
to ensure just and reasonable rates, including those for ancillary 
services, the Commission has continued to evaluate its Avista policy, 
including, with particular regard to this proceeding, 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. The 
Commission's concern has been to ensure that the cost-based OATT 
ancillary service rates of public utilities remain a viable backstop or 
alternative that transmission customers can rely upon instead of the 
market-based sales from third parties who have not been shown to lack 
market power. The Commission has reasoned that, if such third-party 
sellers were permitted to sell to public utilities seeking to meet 
their OATT ancillary service obligations, the public utility's ability 
to seek recovery of such purchase costs in OATT rates might lead to 
increases in those OATT ancillary service rates that may reflect the 
exercise of market power thus reducing the rates' ability to serve as 
an effective alternative to purchases from a third-party seller unable 
to show lack of market power. This would undermine the effectiveness of 
the mitigation measure that the Commission relied upon in Avista to 
relax the requirement for a market power analysis.\20\
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    \20\ 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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    9. However, as the record in this proceeding demonstrates, the 
restriction on sales of ancillary services at market-based rates to a 
public utility for purposes of satisfying its OATT requirements has 
proven to be an

[[Page 46181]]

unreasonable barrier to entry, unnecessarily restricting access to 
potential suppliers. In the NOPR, the Commission proposed to address 
this problem by reforming the Avista restrictions, both by modifying 
the showing an entity must make to establish that it lacks market power 
and by establishing market power mitigation options in the absence of 
such a showing.
    10. Building off the Commission's action in Order No. 755, which 
found that accounting for a given resource's speed and accuracy can 
help ensure just and reasonable rates and prevent against undue 
discrimination, in the NOPR, the Commission also proposed to require 
each public utility transmission provider to include provisions in its 
OATT explaining how it will determine regulation service reserve 
requirements for transmission customers, including those that choose to 
self-supply regulation service, in a manner that takes into account the 
speed and accuracy of resources used.
    11. Finally, the Commission proposed to modify its accounting 
regulations to increase transparency for energy storage facilities. 
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. 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.\21\
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    \21\ 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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Discussion

The Avista Policy

    12. 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 OATT 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. Based on the record before us, the Commission adopts a number 
of the reforms to the ancillary services pricing policy proposed in the 
NOPR and in some instances adopts a number of modifications to those 
reforms based on the comments received in response to the NOPR.
    13. Specifically, this Final Rule allows a resource with market-
based rate authority for sales of energy and capacity to sell imbalance 
services at market-based rates to a public utility transmission 
provider in the same balancing authority area, or to a public utility 
transmission provider in a different balancing authority area, if those 
areas have implemented intra-hour scheduling for transmission service. 
In addition, upon consideration of the comments to the NOPR, this Final 
Rule also allows a resource with market-based rate authority for sales 
of energy and capacity to sell operating reserve services at market-
based rates to a public utility transmission provider in the same 
balancing authority area, or to a public utility transmission provider 
in a different balancing authority area, if those areas have 
implemented intra-hour scheduling for transmission service that 
supports the delivery of operating reserve resources from one balancing 
authority area to another. As a result, the only remaining limitation 
on third-party market-based sales of ancillary services is on sales of 
Reactive Supply and Voltage Control service and Regulation and 
Frequency Response service to a public utility that is purchasing 
ancillary services to satisfy its own OATT requirements absent a 
showing of lack of market power or adequate mitigation of potential 
market power. In that regard, third-party sales of Reactive Supply and 
Voltage Control service and Regulation and Frequency Response service 
to public utility transmission providers will be permitted at rates not 
to exceed the buying public utility transmission provider's OATT rate 
for the same service. Further, to the extent a transmission provider 
chooses to procure either Reactive Supply and Voltage Control service 
or Regulation and Frequency Response service through a competitive 
solicitation that meets the requirements of this Final Rule, third-
party sellers of these services may sell at market-based rates.
    14. While the record in this proceeding was insufficient for the 
Commission to relieve the restrictions for Reactive Supply and Voltage 
Control service and Regulation and Frequency Response service in the 
same manner as Imbalance and Operating reserves, we remain interested 
in exploring the technical, economic and market issues concerning the 
provision of Reactive Supply and Voltage Control service and Regulation 
and Frequency Response service. As such, the Commission intends to 
gather further information regarding the provision of Reactive Supply 
and Voltage Control service and Regulation and Frequency Response 
service in a separate, new proceeding.
    15. Thus, while we decline to adopt some of the reforms proposed in 
the NOPR based on the record in this proceeding, we expect that this 
Final Rule substantially enhances the overall opportunities for third-
parties to compete to make sales of ancillary services while continuing 
to limit the exercise of market power.
    16. We will first discuss the market power analyses used to 
establish authority to sell at market-based rates, followed by a 
discussion of alternative cost-based mitigation in the event a market 
participant cannot show it lacks market power for a specific product or 
service.
Use of Market Power Analyses
    17. The Commission analyzes horizontal market power \22\ 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.\23\ 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.\24\ A seller 
whose share of the relevant market is less than 20 percent during all 
seasons passes the wholesale market share screen.\25\ 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

[[Page 46182]]

market.\26\ A seller satisfies the pivotal supplier screen if its 
uncommitted capacity is less than the net uncommitted supply in the 
relevant market.\27\
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    \22\ 18 CFR 35.37(b) (2012).
    \23\ Order No. 697, FERC Stats. & Regs. ] 31,252 at PP 13, 62. 
See also 18 CFR 35.37(b), (c)(1) (2012).
    \24\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 43. 
Uncommitted capacity is determined by adding the total nameplate or 
seasonal capacity of generation owned or controlled through contract 
and firm purchases, less operating reserves, native load commitments 
and long-term firm sales. Id. P 38.
    \25\ Id. PP 43-44, 80, 89.
    \26\ 18 CFR 35.37(c)(1) (2012).
    \27\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 42.
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    18. 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 with respect to sales of energy or 
capacity; failing either screen creates a rebuttable presumption that 
the seller possesses horizontal market power for such sales.\28\ A 
seller that fails one of the screens may present evidence, such as a 
delivered price test (DPT), to rebut the presumption of horizontal 
market power.\29\ In the alternative, a seller may accept the 
presumption of horizontal market power and adopt some form of cost-
based mitigation.\30\
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    \28\ 18 CFR 35.37(c)(1) (2012).
    \29\ 18 CFR 35.37(c)(2) (2012). For purposes of rebutting the 
presumption of horizontal market power, sellers may use the results 
of the DPT to refine the default relevant geographic market used 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.
    \30\ 18 CFR 35.37(c)(3) (2012).
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    19. 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.\31\ In particular, the Commission will generally use a 
seller's balancing authority area plus first-tier markets,\32\ or the 
RTO/ISO market as applicable, as the default relevant geographic 
market. 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.\33\ Except in the circumstances set forth 
in Avista, entities seeking to sell ancillary services at market-based 
rates have been required to provide market power analyses that address 
the nature and characteristics of each ancillary service, as well as 
the nature and characteristics of generation capable of supplying each 
service.\34\ This requirement was based on an assumption that such 
characteristics might differ from those related to sales of energy and 
capacity.
---------------------------------------------------------------------------

    \31\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 15.
    \32\ First-tier markets are those markets directly 
interconnected to the seller's balancing authority area. See, e.g., 
Order No. 697, FERC Stats. & Regs. ] 31,252 at P 232.
    \33\ 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.
    \34\ See, Ocean Vista, 82 FERC ] 61,114, at 61,406-07 (1998).
---------------------------------------------------------------------------

a. Reliance on Existing Indicative Screens
    20. In the NOPR, the Commission analyzed whether passage of the 
existing market-based rate screens for sales of energy and capacity can 
adequately demonstrate lack of market power for sales of ancillary 
services, based on the relevant characteristics of resources capable of 
providing each ancillary service. Based on this analysis, the 
Commission proposed that only the two imbalance ancillary services 
(Energy Imbalance and Generator Imbalance), and no other ancillary 
services, could be encompassed by the existing market-based rate 
screens.\35\ The Commission sought comment on both this analysis and 
the resulting proposal.\36\
---------------------------------------------------------------------------

    \35\ NOPR, FERC Stats. & Regs. ] 32,690 at PP 18-24.
    \36\ Id. P 24.
---------------------------------------------------------------------------

    21. As discussed in more detail below, commenters addressed both 
the Commission's ancillary service-by-ancillary service analysis of 
this issue, and the proposal to apply the existing market power screens 
to only the imbalance ancillary services.
i. Application to Imbalance Ancillary Services
Commission Proposal
    22. In the NOPR, the Commission stated that resources 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 resources that provide energy or 
capacity. As a result, the Commission proposed that sellers passing 
existing market power analyses should be permitted to sell not only 
energy and capacity in the relevant geographic market(s), but also 
Energy Imbalance and Generator Imbalance services at market-based 
rates. The Commission sought comments on, among other things, any 
unique technical requirements or limitations that might apply to the 
provision of the imbalance ancillary services that might impact the 
Commission's proposal to find that passage of the existing market power 
screens also indicates a lack of market power for imbalance 
services.\37\
---------------------------------------------------------------------------

    \37\ Id. PP 19-20.
---------------------------------------------------------------------------

Comments
    23. The majority of commenters support the Commission's proposal. 
AWEA, Beacon, California Storage Alliance, EEI, Electricity Consumers, 
EPSA, ESA, Iberdrola, Hydro Association, Public Interest Organizations, 
Powerex, Solar Energy Association, Shell Energy, Southern California 
Edison, and WSPP support the NOPR proposal to revise the Commission's 
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.
    24. ESA, Electricity Consumers, Beacon, and EEI, among others, 
agree that there are no special technical requirements or other 
limitations that apply to the provision of the Energy Imbalance or 
Generator Imbalance ancillary services.\38\ Electricity Consumers and 
WSPP, among others, argue that the proposed revisions should reduce 
barriers to ancillary service providers and increase the supply of 
needed ancillary services. WSPP agrees that the proposal would enable 
additional sellers of balancing energy to transact with public utility 
transmission providers in both bilateral markets or a multi-lateral 
balancing market, and states that it would likely foster sales of 
balancing energy even outside of the transmission provider market. AWEA 
contends that the Commission's proposed reforms strike

[[Page 46183]]

the appropriate balance between reducing barriers to entry and 
protecting against market power.
---------------------------------------------------------------------------

    \38\ ESA Comments at 6; Beacon Comments at 5; Electricity 
Consumers Comments at 3; and EEI Comments at 9.
---------------------------------------------------------------------------

    25. WSPP and Powerex, with Iberdrola concurring by reference, urge 
the Commission to clarify that this proposal includes the capacity 
associated with balancing energy sales, not just the energy.\39\ WSPP 
states that without the underlying capacity, sales of balancing energy 
could have no firmness and would be of little value in the market, in 
particular the bilateral market. Further, WSPP contends that the likely 
market for balancing energy would not differentiate energy and capacity 
products by OATT Schedules. Rather, sellers would sell ``flexible 
capacity'' capable of fulfilling multiple OATT Schedules and operators 
would look to flexible capacity to support various system stabilizing 
functions to which the OATT Schedules refer. Thus, WSPP contends that 
the market would be more efficient if the capacity and energy required 
to provide OATT services are not required to be unbundled when the 
natural market for supply would be a bundled ``flexible capacity'' 
product.\40\
---------------------------------------------------------------------------

    \39\ WSPP Comments at 6; and Powerex Comments at 9-10.
    \40\ WSPP Comments at 7.
---------------------------------------------------------------------------

    26. Solar Energy Association states conceptual support for the 
proposal, but argues that sellers may have market power in certain 
ancillary services markets even if not in energy or capacity markets, 
and urges the Commission to police markets that are created due to the 
adoption of a rebuttable presumption of lack of market power.\41\
---------------------------------------------------------------------------

    \41\ Solar Energy Association Comments at 4.
---------------------------------------------------------------------------

    27. Two commenters express concern with the NOPR proposal. TAPS 
objects to the NOPR's preliminary finding that any available unit in a 
given geographic market is capable of providing energy that helps 
address imbalances in that market. TAPS contends that significant 
technical limitations limit the resources that can provide imbalance 
services absent special arrangements like pseudo-ties, and therefore 
the first tier resources included in the horizontal market power screen 
are not generally available to provide intra-hour imbalance service. 
TAPS asserts that Order No. 890-A supports this contention by allegedly 
finding ``that generation outside the control area can provide 
imbalance service when pseudo-tied and thus subject to within-area 
dispatch control.'' \42\ TAPS further states that outside organized 
markets, generators capable of providing imbalance service must have a 
special relationship with the control area operator in order to supply 
changing within-the-hour energy needs, without the constraints of 
hourly transmission scheduling requirements and that even the recently 
adopted 15-minute scheduling requirement is insufficient, especially 
when combined with the need to schedule 20 minutes in advance.\43\
---------------------------------------------------------------------------

    \42\ TAPS Comments at 11-12.
    \43\ Id. at 11-13.
---------------------------------------------------------------------------

    28. TAPS asserts that, in non-RTO regions, imbalance service is 
typically provided by the energy associated with regulation and 
operating reserves, and thus resources capable of providing imbalance 
services would necessarily be subject to the same technical 
requirements as the NOPR described for regulation and operating 
reserves.\44\ TAPS supports this assertion by claiming that Order No. 
890 found that ``demand costs of providing imbalance service are 
already being provided under Schedule 3, 5, and 6 charges [i.e., 
Regulation and Frequency Response Service, Operating Reserve-Spinning 
Reserve Services, and Operating Reserve Supplemental Reserve 
Services].'' \45\
---------------------------------------------------------------------------

    \44\ Id. at 12-13.
    \45\ Id. at 12 (citing Order No. 890, FERC Stats. & Regs. ] 
31,241 at P 690).
---------------------------------------------------------------------------

    29. TAPS further rejects the Commission's assertion in the NOPR 
that this proposal is consistent with the 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.\46\ TAPS contends that 
the pricing of OATT imbalance service does not demonstrate the absence 
of the alleged restrictions described above on the supply of intra-hour 
energy that allows transmission providers to provide energy imbalance 
service.
---------------------------------------------------------------------------

    \46\ NOPR, FERC Stats. & Regs. ] 32,690 at P 19 (citing Order 
No. 890-A, FERC Stats. & Regs. ] 31,261 at P 309).
---------------------------------------------------------------------------

    30. Morgan Stanley contends that the existing market power screens 
are flawed even in their application to energy and capacity products 
and thus should not be applied to additional products. Morgan Stanley 
argues that the existing market power screens in some cases fail to 
assess the full import capability into a given geographic market, and 
thus the true market size. Morgan Stanley ultimately argues that a 
revised market power screen ``should include any transmission located 
outside of the relevant market area, but which is interconnected and 
over which there is transfer capacity.'' \47\ However, Morgan Stanley 
does not state opposition to the idea that a lack of market power in 
energy and capacity can justify an assumption of equivalent lack of 
market power in Energy Imbalance and Generator Imbalance services.
---------------------------------------------------------------------------

    \47\ Morgan Stanley Comments at 2-5.
---------------------------------------------------------------------------

Commission Determination
    31. The Commission will adopt its proposal with modification. The 
Commission will allow third-party sellers passing existing market power 
screens to sell Energy Imbalance and Generator Imbalance services at 
market-based rates to a public utility transmission provider within the 
same balancing authority area, or to a public utility transmission 
provider in a different balancing authority area, if those areas have 
implemented intra-hour scheduling for transmission service.\48\ The 
Commission continues to believe that there are no unique technical 
requirements or limitations that apply to a resource's provision of 
Energy Imbalance or Generator Imbalance services. However, the 
Commission agrees with TAPS that the delivery of Energy Imbalance and 
Generator Imbalance services may be limited by hourly transmission 
scheduling practices in place within certain regions and, as such, 
refines the NOPR proposal as discussed below.
---------------------------------------------------------------------------

    \48\ We note that sales of Energy Imbalance and Generator 
Imbalance services to entities other than a public utility 
transmission provider remain authorized under Avista.
---------------------------------------------------------------------------

    32. Energy Imbalance and Generator Imbalance services are a subset 
of a broader set of ancillary services offered by a public utility 
transmission provider to manage system conditions and ensure reliable 
transmission service. Energy Imbalance and Generator Imbalance services 
involve the balancing of differences between scheduled and actual 
delivery of energy or output of generation over an hour.\49\ In 
comparison, Regulation and Frequency Response service involves the 
matching of resources to load in a shorter timeframe, requiring 
automated dispatch at four- or five-second intervals.\50\ As a result, 
resources used

[[Page 46184]]

to provide Regulation and Frequency Response service must be capable of 
balancing moment-to-moment fluctuations, whereas resources used to 
provide Energy and Generator Imbalance can respond at longer time 
frames within the hour.
---------------------------------------------------------------------------

    \49\ See pro forma OATT, Schedules 4 and 9. Under the pro forma 
OATT, imbalances are calculated and charged on an hourly basis. See 
Order No. 890, FERC Stats. & Regs. ] 31,241 at P 722; Order No. 890-
A, FERC Stats. & Regs. ] 61,297 at P 325 & n.117; see also Order No. 
764, FERC Stats. & Regs. ] 32,331 at P 104. Energy Imbalance and 
Generator Imbalance services also may be self-supplied by a 
transmission customer.
    \50\ See, e.g., Pro Forma OATT, Schedule 3 Regulation and 
Frequency Response Service--``Regulation and Frequency Response 
Service is necessary to provide for the continuous balancing of 
resources (generation and interchange) with load . . . .''
---------------------------------------------------------------------------

    33. In practice, public utility transmission providers often have a 
portfolio of resources, some owned and some purchased from third-
parties, from which they provide capacity, energy, and ancillary 
services. This portfolio typically includes resources with automatic 
generation control (AGC) equipment capable of handling both moment-by-
moment frequency adjustments and longer duration imbalance needs, as 
well as other capacity and energy resources that may only be capable of 
addressing longer duration imbalance needs because they are not 
equipped with AGC. These longer duration resources may include block 
purchases from third parties that are dispatched or otherwise scheduled 
at varying timeframes. The relative amount of AGC-controlled and other 
resources used by a public utility transmission provider for intra-hour 
balancing will depend on the resources available and the public utility 
transmission provider's operating practices.
    34. In the NOPR, the Commission did not separately discuss this 
range of resources and, instead, preliminarily concluded that there are 
no unique technical requirements or limitations that distinguish the 
resources capable of providing energy and capacity from those capable 
of providing imbalance services. The majority of commenters agree with 
the Commission's preliminary conclusion, arguing that the set of 
resources available to follow imbalances over an hour is the same set 
of resources capable of providing energy and capacity. However, TAPS 
disagrees, arguing that the set of resources capable of providing 
imbalance services must have a special relationship with the control 
area operator in order to supply changing within-the-hour energy needs.
    35. We understand TAPS' argument to be that resources used to 
provide imbalance service must be able to respond to a dynamic four- or 
five-second signal, which might require special arrangements in order 
to permit imbalance sales outside of the resource's home balancing 
authority area such that even the ability to submit transmission 
schedules on a 15-minute basis would be insufficient to provide intra-
hour imbalance energy.\51\ We agree that some of the public utility 
transmission provider's energy imbalance needs are addressed by 
resources that manage the moment-by-moment difference between load and 
resources. We also agree that imbalance service would generally require 
deliveries on intervals shorter than the current hour. But we do not 
agree, as explained more fully below, that imbalance services require 
dynamic dispatch or more sophisticated delivery mechanisms than intra-
hour transmission scheduling.
---------------------------------------------------------------------------

    \51\ TAPS Comments at 13.
---------------------------------------------------------------------------

    36. Under the pro forma OATT, imbalances are calculated on an 
hourly basis.\52\ As a result, any energy deliveries within the hour 
can be used by a public utility transmission provider (or by a 
transmission customer) to manage imbalances across the hour. That is, 
energy deliveries within the hour can be included in the portfolio of 
resources used to follow imbalance trends across the hour, similar to a 
public utility transmission provider's decision to redispatch its own 
internal resources within the hour. While it is true, as TAPS states, 
that dynamically dispatched resources capable of providing regulation 
also would be capable of providing imbalance services, it does not 
follow that resources using intra-hour transmission schedules are 
incapable of providing imbalance services. As noted above, imbalance 
service can be provided from a collection of resources so long as they 
are deliverable within the hour.\53\
---------------------------------------------------------------------------

    \52\ See Order No. 890, FERC Stats. & Regs. at P 722, order on 
reh'g, Order No. 890-A, FERC Stats. & Regs. ] 61,297 at P 325 & 
n.117; see also Order No. 764, FERC Stats. & Regs. ] 32,331 at P 
104.
    \53\ The Commission acknowledges that energy purchases scheduled 
on an hourly basis might enable a public utility transmission 
provider to use other resources to provide imbalance or other 
ancillary services more efficiently or precisely. Such hourly sales 
of energy would not be an indirect sale of ancillary services within 
the meaning of Avista.
---------------------------------------------------------------------------

    37. The question before the Commission here is whether the set of 
resources considered available to provide energy and capacity in a 
market power analysis is sufficiently similar to the set of resources 
capable of providing imbalance services. Based on the record before us 
in which numerous commenters agree that the resources are sufficiently 
similar and given that intra-hour transmission schedules are currently 
being offered by a number of public utility transmission providers, and 
must be offered by all public utility transmission providers under 
Order No. 764 on or before November 12, 2013,\54\ the Commission finds 
it appropriate at this time to revise the Avista restriction to better 
reflect current operational realities.
---------------------------------------------------------------------------

    \54\ In order to comply with Order No. 764, public utility 
transmission providers must allow transmission customers to modify 
existing schedules as well as create new transmission schedules at 
intervals not to exceed 15 minutes, on or before November 12, 2013. 
Order No. 764, FERC Stats. & Regs. ] 32,331 at P 91, order on reh'g, 
Order 764-A, 141 FERC ] 61,232.
---------------------------------------------------------------------------

    38. With regard to TAPS' additional comments in support of its 
basic argument, as stated above, just because a public utility 
transmission provider may have chosen to rely on the energy associated 
with regulation or operating reserves to meet imbalances, it does not 
follow that those are the only resources capable of providing imbalance 
services. Moreover, TAPS' reference to a portion of a passage from 
Order No. 890 referring to demand costs of providing imbalance energy 
being recoverable through regulation (Schedule 3) and operating reserve 
(Schedules 5 and 6) services is not dispositive here. The rate 
mechanisms used by a public utility transmission provider to recover 
the cost of capacity associated with providing Energy Imbalance or 
Generator Imbalance service do not precisely reflect the technical 
capabilities of resources available to provide the imbalance services. 
There is no requirement, in past Commission pronouncements or 
otherwise, that imbalance services be provided only from resources 
capable of providing regulation or operating reserves. Indeed, TAPS 
criticizes the NOPR for asserting the Commission's proposal was 
consistent with the decision in Order No. 890-A to base cost-based 
imbalance charges 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.\55\ We agree with TAPS that the pricing of 
OATT imbalance services does not necessarily determine the technical 
capabilities of resources available to provide those services and 
reject the NOPR's assertion in this regard. Similarly, we find that the 
pricing of regulation and operating reserve services, whether through 
Schedules 3, 5, 6 or some other mechanism (such as generator regulation 
service), do not necessarily determine the technical capabilities of 
resources available to provide imbalance services.
---------------------------------------------------------------------------

    \55\ See NOPR, FERC Stats. & Regs. ] 32,690 at P 19 (citing 
Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 309).
---------------------------------------------------------------------------

    39. TAPS also cites Order No. 890-A as finding that generation 
outside a control area can provide imbalance

[[Page 46185]]

service when pseudo-tied and thus subject to within-area dispatch.\56\ 
The cited passage of Order No. 890-A, however, states that a pseudo-tie 
arrangement causes a control area to ``assum[e] responsibility for 
ensuring that the load is properly balanced moment-to-moment, for 
planning for the load, and for providing various other ancillary 
services including energy or generator balancing service.'' The 
Commission made no determination in that passage as to the universe of 
resources capable, or incapable, of providing imbalance services. 
Nevertheless, the Commission acknowledges that some public utility 
transmission providers may choose not to purchase imbalance service 
from resources that cannot also be dynamically dispatched. While that 
may inform the relative ability of a resource to find a buyer for its 
service, it does not define the set of resources from which imbalance 
services are available, which is the relevant question for market power 
analyses.
---------------------------------------------------------------------------

    \56\ TAPS Comments at 12 (citing Order No. 890-A, FERC Stats. & 
Regs. ] 31,261 at P 631).
---------------------------------------------------------------------------

    40. We also find the opposing arguments of Morgan Stanley to be 
beyond the scope of this proceeding. Morgan Stanley does not appear to 
object to the use of the same market power screens for energy, capacity 
and imbalance services. Rather, Morgan Stanley argues that the existing 
indicative screens should be reformulated to include greater 
transmission imports than are currently assumed. Arguments as to the 
make-up of the existing market power screens are beyond the scope of 
this proceeding. The question before us in this proceeding is whether 
the resources in a given geographic market capable of providing 
imbalance ancillary services are sufficiently similar to the resources 
capable of providing energy and capacity that the same market power 
analysis can apply to both sets of products. Moreover, the Commission 
already permits applicants to demonstrate that the relevant geographic 
market is larger or smaller than that default.\57\
---------------------------------------------------------------------------

    \57\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 268.
---------------------------------------------------------------------------

    41. Accordingly, this Final Rule establishes that sellers found to 
lack market power in a geographic market, and which are granted market-
based rate authority to make sales of energy and capacity, will also be 
granted market-based rate authority for sales of Energy Imbalance and 
Generator Imbalance services to public utility transmission providers 
within the same balancing authority area, or to public utility 
transmission providers in different balancing authority areas, if those 
areas allow transmission customers to modify or create transmission 
schedules within the hour. Because, as explained above, such scheduling 
practices enable the delivery of within-hour imbalance services from 
one balancing authority area to another, their use ensures that the 
first-tier resources included in the existing market power screens can 
compete with resources in the home balancing authority area, and thus 
that the existing market power screens can be applied to imbalance 
services without modification. This finding applies both to sellers 
that currently have a market-based rate tariff on file and applicants 
seeking market-based rate authority. For administrative convenience, we 
make this change to the Commission's ancillary services pricing policy 
effective as of the effective date of this Final Rule (120 days after 
publication in the Federal Register), which will result in these 
changes becoming effective after November 12, 2013, the date by which 
all public utility transmission providers must offer intra-hour 
transmission scheduling. As noted above, we acknowledge that some 
transmission providers already offer intra-hour scheduling. However, 
rather than performing a transmission provider-by-transmission provider 
review of current scheduling practices in this rulemaking, the 
Commission will defer implementation of this change to our ancillary 
services pricing policy until after the effectiveness of the intra-hour 
scheduling requirements of Order No. 764, by which time all public 
utility transmission providers must offer intra-hour scheduling. Thus, 
as of the effective date, all sellers that have a market-based rate 
tariff on file as of that date may begin making third-party sales of 
Energy Imbalance and Generator Imbalance services at market-based rates 
to a public utility transmission provider that is purchasing Energy 
Imbalance and Generator Imbalance services to satisfy its own open 
access transmission tariff requirements to offer ancillary services to 
its own customers, without having to make a separate showing to the 
Commission.
    42. In response to WSPP, we clarify that this authorization to 
undertake sales at market-based rates may include both the capacity and 
the energy associated with providing Energy Imbalance and Generator 
Imbalance services. Imbalance services are products designed to address 
differences between scheduled and actual deliveries and withdrawals of 
energy. As such, they can only be provided by ensuring the availability 
of capacity and then increasing or decreasing the energy output from 
that capacity as necessary to address these differences.\58\
---------------------------------------------------------------------------

    \58\ See, e.g., Order No. 764, FERC Stats. & Regs. ] 32,331 at P 
240.
---------------------------------------------------------------------------

ii. Application to Other Ancillary Services
Commission Proposal
    43. In the NOPR, the Commission proposed to allow the existing 
market-based rate screens to be applied to Energy Imbalance and 
Generator Imbalance services, but sought comment on whether the 
characteristics of resources used to provide the other ancillary 
services 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.\59\
---------------------------------------------------------------------------

    \59\ NOPR, FERC Stats. & Regs. ] 32,690 at P 24.
---------------------------------------------------------------------------

    44. With regard to Operating Reserve-Spinning and Operating 
Reserve-Supplemental, the NOPR discussed the technical considerations, 
such as minimum ramp and start-up rates for off-line resources and the 
ability for extended operation below fully loaded set point for online 
resources, that seemed to indicate that fewer resources would be 
capable of providing these ancillary services as compared to the set of 
resources capable of providing energy or capacity. With regard to 
Reactive Supply and Voltage Control from Generation Sources, the NOPR 
discussed the technical and geographic considerations that generally 
limit the resources capable of providing this ancillary service as 
compared with the broader set of resources capable of providing energy 
or capacity. With regard to Regulation and Frequency Response, the 
Commission discussed the technical requirements, such as automatic 
generation control (AGC) equipment, that limit the set of resources 
capable of supplying this ancillary service.\60\
---------------------------------------------------------------------------

    \60\ Id. PP 22-23.
---------------------------------------------------------------------------

Comments
    45. A number of commenters argue for application of the existing 
market power screens to Operating Reserve-Spinning and Operating 
Reserve-Supplemental.\61\ EPSA argues that operating reserves are

[[Page 46186]]

merely derivatives of a resource's ability to generate energy.\62\
---------------------------------------------------------------------------

    \61\ EPSA Comments at 6, WSPP Comments at 8 (with Iberdrola 
supporting by reference), EEI Comments at 3 and 10, Western Group 
Comments at 3-4, Hydro Association Comments at 7, and Powerex 
Comments at 7 and 13.
    \62\ EPSA Comments at 6.
---------------------------------------------------------------------------

    46. WSPP argues that the same considerations that led the 
Commission to believe that the rebuttable presumption should be 
extended to the imbalance ancillary services also apply to the 
operating reserve ancillary services. WSPP further asserts that all of 
these ancillary services are widely deliverable and that all generators 
capable of being redispatched to higher or lower set-points within a 
scheduling window are capable of providing these ancillary 
services.\63\
---------------------------------------------------------------------------

    \63\ WSPP Comments at 8. Iberdrola supports these WSPP comments 
by reference.
---------------------------------------------------------------------------

    47. EEI argues that except for variable energy resources, 
essentially the same set of resources evaluated as competing supply 
under the existing market power screens possess the required technical 
capabilities to provide operating reserves.\64\ Western Group makes a 
similar argument, asserting that products in Schedules 3, 5, and 6 
(Regulation and Operating Reserves) share operational characteristics 
of Schedules 4 and 9 (Imbalance services).\65\
---------------------------------------------------------------------------

    \64\ EEI Comments at 10.
    \65\ Western Group Comments at 3.
---------------------------------------------------------------------------

    48. While Powerex agrees that resources capable of providing 
spinning and non-spinning reserves may be limited by response time 
requirements, Powerex argues that the existing market power screens 
nonetheless can be applied to operating reserve services.\66\
---------------------------------------------------------------------------

    \66\ Powerex Comments at 7 and 13.
---------------------------------------------------------------------------

    49. With respect to Regulation and Frequency Response, some 
commenters argue that passage of the existing market power screens 
indicates lack of market power for that service. For example, while 
EPSA agrees that the market power of sellers of Reactive Supply and 
Voltage Control service cannot be gauged by the existing market power 
screens due to significant technical and geographic impediments, it 
argues that Regulation and Frequency Response service is merely a 
derivative of a resource's ability to generate energy. Accordingly, 
EPSA argues that application of the existing market power screens to 
this ancillary service would be appropriate.\67\
---------------------------------------------------------------------------

    \67\ EPSA Comments at 6.
---------------------------------------------------------------------------

    50. Powerex agrees that the existing market power screens could be 
applied to Regulation and Frequency Response service. Powerex believes 
that technical improvements such as the dynamic scheduling system 
adopted by some users of the Western Interconnection facilitate 
widespread delivery of regulating reserves, thus overcoming any 
locational requirements for that service, while any technical 
impediments could be overcome because AGC or equivalent power 
electronic controls could be added by most market participants if the 
markets provide correct price signals.\68\ WSPP similarly argues that, 
while not all generators have the AGC equipment needed to provide 
Regulation and Frequency Response service, installation of this 
capability is an economic decision and is not such an impediment that 
it should be treated as a market defining barrier to entry.\69\
---------------------------------------------------------------------------

    \68\ Powerex Comments at 12.
    \69\ WSPP Comments at 8. Iberdrola supports these WSPP comments 
by reference.
---------------------------------------------------------------------------

    51. FTC Staff urges the Commission to recognize that even though a 
particular resource may not currently have the ability to provide a 
given ancillary service due to lack of relevant equipment, if such 
equipment could be installed in a timely fashion in response to high 
prices, then such resource should be considered a potential competitor 
for purposes of market power analysis. Accordingly, FTC Staff suggests 
that the Commission revise its market power analysis to incorporate as 
existing market participants those potential entrants that are likely 
to enter a given ancillary service market (i.e., install needed 
equipment such as AGC) rapidly and profitably should market prices 
justify such entry.\70\
---------------------------------------------------------------------------

    \70\ FTC Staff Comments at 6-8.
---------------------------------------------------------------------------

    52. EEI argues that, before extending application of the existing 
market power screens to Regulation and Frequency Response, the 
Commission should separate this service into two separate ancillary 
services: primary frequency control and secondary frequency control. 
EEI argues that secondary frequency control, which it labels as 
Regulation, is a prime candidate to be extended the rebuttable 
presumption (i.e., to be subject to the existing market power 
screens).\71\
---------------------------------------------------------------------------

    \71\ EEI Comments at 10-11.
---------------------------------------------------------------------------

    53. Two parties filed comments opposing the application of existing 
market power screens to non-imbalance ancillary services. Southern 
California Edison and TAPS state that they agree with the NOPR's 
reasoning as to why the existing market power screens cannot be applied 
to non-imbalance ancillary services.\72\ Remaining commenters did not 
address the question of applying the existing market power screens to 
non-imbalance ancillary services.
---------------------------------------------------------------------------

    \72\ Southern California Edison Comments at 1-2; and TAPS 
Comments at 9-10.
---------------------------------------------------------------------------

Commission Determination
    54. Upon consideration of the comments to the NOPR, and as 
discussed more fully below, the Commission will allow third-party 
sellers passing existing market power screens to sell Operating 
Reserve-Spinning and Operating Reserve-Supplemental services at market-
based rates to a public utility transmission provider within the same 
balancing authority area, or to a public utility transmission provider 
in a different balancing authority area, if those areas have 
implemented intra-hour scheduling for transmission service that 
supports the delivery of operating reserve resources from one balancing 
authority area to another. Commenters have persuaded us that to the 
extent there are technical requirements and limitations associated with 
operating reserves, they do not materially distinguish resources 
capable of providing energy and capacity from those capable of 
providing operating reserves. As with the imbalance services, however, 
the Commission finds that the delivery of operating reserves from one 
balancing authority area to another may be limited by hourly scheduling 
practices in place within certain regions, which could impact the 
assumption in the existing market power screens that first-tier 
resources are able to compete with home balancing authority area 
resources. Therefore, the Commission will allow third-party sellers 
passing existing market power screens to sell these services to public 
utility transmission providers to the extent within-hour transmission 
service scheduling practices, including intra-hour transmission 
scheduling mandated by Order No. 764, support the delivery of operating 
reserves from one balancing authority area to another.
    55. In contrast, the Commission affirms the preliminary finding in 
the NOPR that the set of resources capable of providing Regulation and 
Frequency Response service and Reactive Supply and Voltage Control 
service would differ significantly from the broader set of resources 
capable of supplying energy and capacity. Accordingly, the Avista 
restrictions will remain in place for sales of those services to public 
utility transmission providers at market-based rates. As noted below, 
the Commission will establish a new proceeding to further explore the 
technical, economic and market issues concerning the provision of 
Reactive Supply and Voltage Control service and Regulation and 
Frequency Response service.

[[Page 46187]]

Operating Reserve Services
    56. Operating Reserve-Spinning and Operating Reserve-Supplemental 
are products designed to serve load temporarily in the event of 
contingencies. As such, sellers must ensure the availability of 
capacity sufficient to address a contingency event and, if the 
contingency occurs, energy must be supplied from that capacity. While 
the NOPR preliminarily found that the operating reserve products 
appeared to require the availability of resources with relatively fast 
ramping capabilities, and in the case of off-line resources used for 
operating reserve-supplemental, relatively fast start-up capabilities 
as well,\73\ comments to the NOPR argue otherwise.
---------------------------------------------------------------------------

    \73\ See NOPR, FERC Stats. & Regs. ] 32,690 at P 22.
---------------------------------------------------------------------------

    57. Many comments to the NOPR make the case that the flexibility 
and response time requirements associated with operating reserve 
services are not so significant that the universe of resources that can 
provide these services is meaningfully different than the universe of 
resources used to assess energy and capacity market power. While 
traditional generation scheduling practices only require the resources 
that provide energy and capacity to be able to change output levels 
once an hour, the record in this proceeding indicates that most 
resources can change output levels on shorter time scales. In other 
words, most conventional resources can change output in response to 
contingency events on a time scale shorter than the typical hourly 
scheduling window, even if in the past they have only been selling 
hourly block energy and capacity. Therefore, the Commission will allow 
third-party sellers passing existing market power screens for energy 
and capacity for a given market to also sell Operating Reserves-
Spinning and Operating Reserves-Supplemental services at market-based 
rates to a public utility transmission provider within the same 
balancing authority area, or to a public utility transmission provider 
in a different balancing authority area, if within-hour transmission 
scheduling practices in those areas support the delivery of operating 
reserves from one balancing authority area to another.\74\
---------------------------------------------------------------------------

    \74\ As with Energy Imbalance and Generator Imbalance services, 
we clarify that the authorization to undertake sales at market-based 
rates may include both the capacity and the energy associated with 
providing Operating Reserve-Spinning and Operating Reserve-
Supplemental services.
---------------------------------------------------------------------------

    58. We note that our approach for market-based sales of operating 
reserves differs slightly from the reforms adopted above for sales of 
imbalance services. We have found above that the existence of 15-minute 
scheduling in a region renders the set of resources capable of 
supplying imbalance services substantially similar to the set of 
resources capable of providing energy and capacity so that the same 
market power screens can be applied to both sets of services. This may 
not be the case in all circumstances for potential sellers of operating 
reserves and, therefore, we require such entities to explain in their 
market-based rate applications for such authority how the scheduling 
practices in their regions support the use of operating reserves. For 
example, while 15-minute scheduling might be sufficient for Operating 
Reserve-Supplemental because this service only requires designated 
resources to be available within a short period of time,\75\ 15-minute 
scheduling by itself may not be sufficient for Operating Reserve-
Spinning, which requires designated resources to be available 
immediately.\76\ The Commission recognizes that unlike the imbalance 
services, operating reserve services are targeted only at addressing 
contingency events, and some regions such as WECC may have already 
developed within-hour capacity tagging and scheduling practices 
intended to support the use of operating reserves across multiple 
balancing authority areas.\77\ These are the types of region-specific 
practices that sellers seeking authority to sell operating reserves to 
public utility transmission providers should describe in their market-
based rate applications. Thus, as of the effective date of this Final 
Rule, both sellers that have a market-based rate tariff on file as of 
that date and applicants seeking new market-based rate authority must 
satisfactorily make the above showing and receive Commission 
authorization before making sales of Operating Reserve-Spinning and 
Operating Reserve-Supplemental to a public utility that is purchasing 
Operating Reserve-Spinning and Operating Reserve-Supplemental to 
satisfy its own open access transmission tariff requirements to offer 
ancillary services to its own customers.
---------------------------------------------------------------------------

    \75\ See pro forma OATT, Schedule 6 ``Supplemental Reserve 
Service is needed to serve load in the event of a system 
contingency; however, it is not available immediately to serve load 
but rather within a short period of time.''
    \76\ Id. Schedule 5 ``Spinning Reserve Service is needed to 
serve load immediately in the event of a system contingency.''
    \77\ See, e.g., WECC Regional Business Practice INT-018-WECC-
RBP-0, Tagging Protocols, at WR5.1 and WR5.2, defining capacity e-
tags for, respectively, spinning reserves and non-spinning reserves 
as ``product(s) that can be activated through the adjustment of a 
capacity e-tag.'' Available at http://www.wecc.biz/library/Documentation%20Categorization%20Files/Forms/AllItems.aspx?RootFolder=%2flibrary%2fDocumentation%20Categorization%20Files%2fRegional%20Business%20Practices&FolderCTID=0x01200015E7900DB2E794468FDE06D520B95C07.
---------------------------------------------------------------------------

Regulation and Reactive Power Services
    59. The Commission affirms the preliminary finding in the NOPR that 
the more stringent technical and geographic considerations associated 
with the regulation and reactive power ancillary services suggest that 
they are not simple combinations of basic energy and capacity products. 
Most commenters addressing this issue agree that the set of resources 
considered by the existing market power screens would differ too 
significantly from the set of resources that would be considered by 
market power analyses designed specifically for Reactive Supply and 
Voltage Control service.
    60. While some commenters do argue that the existing market power 
screens are adequate for Regulation and Frequency Response service, we 
are not persuaded by their arguments on the record here. We continue to 
believe that significant technical requirements, such as the need for 
AGC equipment, limit the set of resources capable of supplying this 
ancillary service. While we agree in principle with FTC Staff's 
comments that potential competitors could be viewed as existing 
competitors for purposes of market power analysis if it is known that 
they can install needed equipment rapidly and profitably in response to 
appropriate price signals, the record does not conclusively support the 
notion that such equipment upgrades (e.g., to install AGC equipment in 
an existing generator) can be accomplished in such a manner. Although 
Powerex asserts that AGC or equivalent power electronic controls could 
be added by most market participants if the markets provide correct 
price signals, and WSPP asserts that the addition of AGC is an economic 
decision, we are not persuaded based on the limited information in the 
record before us. Also, the record indicates that third-party sellers 
of Regulation and Frequency Response service might need to enter into 
or facilitate special arrangements between neighboring balancing 
authorities, such as dynamic scheduling or pseudo-tie arrangements, in 
order to make sales outside of their home balancing authority area.
    61. Accordingly, because the record before us does not support a 
modification at this time, the Avista restrictions will remain in place 
for sales of Regulation and Frequency Response and Reactive Supply and

[[Page 46188]]

Voltage Control services to a public utility transmission provider that 
is purchasing these ancillary services to satisfy its own OATT 
requirements to offer ancillary services to its own customers. However, 
the Commission intends to gather more information regarding this issue 
in a separate, new proceeding that will further explore the technical, 
economic and market issues concerning the provision of Reactive Supply 
and Voltage Control service and Regulation and Frequency Response 
service. Such proceeding will consider, among other things, the ease 
and cost-effectiveness of relevant equipment upgrades, the need for and 
availability of appropriate special arrangements such as dynamic 
scheduling or pseudo-tie arrangements, and other technical requirements 
for provision of Regulation and Frequency Response and Reactive Supply 
and Voltage Control services.
b. Optional Market Power Screen
Commission Proposal
    62. In the NOPR, the Commission proposed a new optional market 
power screen solely applicable to ancillary services, together with a 
limited new reporting requirement that would provide potential sellers 
of ancillary services with the information needed to develop market 
power analyses using that optional market power screen.\78\ 
Specifically, the optional market power screen for an ancillary service 
would 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 aggregate 
requirement for that ancillary service, taking into account any 
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 aggregate requirement for an ancillary service would 
receive a rebuttable presumption that they lack horizontal market power 
for the ancillary service in question.
---------------------------------------------------------------------------

    \78\ NOPR, FERC Stats. & Regs. ] 32,690 at PP 25-30.
---------------------------------------------------------------------------

    63. In order to provide sellers with information as to the buyer's 
aggregate requirement for an ancillary service, the Commission proposed 
to require each public utility transmission provider to publicly post 
on its OASIS 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. For example, a transmission provider may report that it 
has historically maintained 100 MW of Regulation and Frequency Response 
reserves for its balancing authority area and 100 MVAR of Reactive 
Supply and Voltage Control in each of two submarkets within its 
balancing authority area.
Comments
    64. Some commenters support the optional market power screen on the 
basis that it provides a practical alternative to performing a 
traditional market power analysis, given the data constraints 
associated with the latter. WSPP, for example, states that the optional 
market power screen is a constructive response to the disconnection 
between regulatory market power study requirements and the incapability 
of market participants to perform those studies due to lack of 
data.\79\ WSPP states that it strongly supports the Commission's 
proposal that public utility transmission providers be required to post 
the information needed for sellers to prepare the optional market power 
screen if the rebuttable presumption applicable to the imbalance 
ancillary service is not extended to all ancillary services.\80\
---------------------------------------------------------------------------

    \79\ WSPP Comments at 12.
    \80\ Id. at 10.
---------------------------------------------------------------------------

    65. Public Interest Organizations argue that the optional screen is 
similar in intent to a de minimis capacity threshold and, as such, can 
remove the barrier of a burdensome market power analysis for smaller 
entities.\81\ The Solar Energy Association asserts that the optional 
market power screen likely will broaden the number of participants in 
the markets for certain ancillary services.\82\ Electricity Consumers 
similarly argues that the optional market power screen should reduce 
barriers to ancillary service providers and increase the supply of 
ancillary services in a timely and cost-effective manner.\83\
---------------------------------------------------------------------------

    \81\ Public Interest Organizations Comments at 6.
    \82\ Solar Energy Association Comments at 5.
    \83\ Electricity Consumers Comments at 3.
---------------------------------------------------------------------------

    66. However, there was no consensus among the commenters supporting 
the proposed optional market power screen regarding the necessary 
granularity of the associated reporting requirement. Some commenters, 
such as WSPP and Shell Energy, argue that postings should reflect a 
transmission provider's annual peak requirements for ancillary 
services, rather than annual averages. WSPP argues that posting an 
annual average would tend to understate requirements for higher 
periods, thereby skewing screen results in the direction of 
violations.\84\ Similarly, Shell Energy states that relying on annual 
peaks is preferable to annual averages because it better reflects the 
amounts that transmission providers need to procure. Shell Energy 
further argues that postings of annual peak values are preferable to 
postings of seasonal or quarterly values, which Shell Energy claims 
would be burdensome for transmission providers and suppliers.\85\
---------------------------------------------------------------------------

    \84\ WSPP Comments at 11.
    \85\ Shell Energy Comments at 8.
---------------------------------------------------------------------------

    67. Conversely, the ESA, Beacon, and California Storage Alliance 
recommend that public utilities provide seasonal and time-of-day 
requirements (if any) for each ancillary service versus a single 
average annual amount and note that this is consistent with the type of 
data provided by RTOs/ISOs in the open wholesale markets.\86\
---------------------------------------------------------------------------

    \86\ ESA Comments at 7; Beacon Comments at 6; and California 
Storage Alliance Comments at 4.
---------------------------------------------------------------------------

    68. Some commenters oppose the optional market power screen, 
arguing that it would yield too many false positives because it does 
not measure a seller's ability to supply relative to the total 
potential supply of the overall market. EPSA, for example, argues that 
the optional screen would routinely result in false-positive 
indications of market power.\87\ EPSA states that if the Commission 
decides to use a threshold test, it should compare the subject 
generator to total product capability, not merely the quantity 
demanded.\88\ EEI similarly argues that the optional screen likely will 
result in many suppliers failing the 20 percent threshold.\89\ EEI 
contends that there are alternatives that would refine the test to be 
more applicable and useful in promoting robust participation in 
competitive ancillary services markets in bilateral regions. EEI offers 
as an example requiring transmission providers to report on its OASIS 
in the aggregate its historical demand and its historical ability to 
supply the relevant ancillary services. EEI offers that if the 
Commission decides to pursue optional screen it should have a technical 
conference.\90\
---------------------------------------------------------------------------

    \87\ EPSA Comments at 6.
    \88\ Id. at 7.
    \89\ EEI Comments at 16.
    \90\ EEI Comments at 15.
---------------------------------------------------------------------------

    69. Powerex claims that the optional market power screen does not 
appear workable in certain respects and is likely to result in too many 
false positives.\91\ Powerex argues that establishing a test that is 
overly restrictive, and that a majority of sellers

[[Page 46189]]

will not be able to satisfy, will create a significant administrative 
burden that will continue to pose an obstacle to the development of 
competitive markets for ancillary services.\92\ Powerex asserts that 
when using market shares as a metric of market power, the proper 
measurement is a seller's ability to supply relative to the total 
potential supply of the overall market.\93\
---------------------------------------------------------------------------

    \91\ Powerex Comments at 16.
    \92\ Id. at 17.
    \93\ Id. at 19.
---------------------------------------------------------------------------

    70. Morgan Stanley argues that the optional market power screen 
does not provide a complete picture of an entity's market power and 
that it is more relevant to compare the amount of supply a seller 
controls to the total supply available and the total market demand, 
than it is to compare it to a single buyer's requirements.\94\ Morgan 
Stanley claims that a seller actually could have greater market power 
even if it only can serve a small portion of the buyer's aggregate 
requirements if the buyer has no other viable options for procuring the 
remaining portion of its ancillary service needs.\95\
---------------------------------------------------------------------------

    \94\ Morgan Stanley Comments at 6.
    \95\ Id. at 7.
---------------------------------------------------------------------------

    71. Other commenters oppose the optional market power screen on the 
basis that its need and usefulness is unclear. For example, TAPS argues 
that the usefulness of the optional screen is uncertain, particularly 
given the acknowledged data limitations. TAPS further argues that one 
cannot be confident that the proxy would provide a meaningful screen 
for market power.\96\
---------------------------------------------------------------------------

    \96\ TAPS Comments at 14.
---------------------------------------------------------------------------

    72. The California PUC states that is sees no need for alternative 
methodologies and further argues that a 20 percent threshold is too 
high for ancillary services.\97\ The Hydro Association also states that 
it does not see a need at this time for the Commission to develop 
alternative market screens.\98\
---------------------------------------------------------------------------

    \97\ California PUC Comments at 5-6.
    \98\ Hydro Association Comments at 8.
---------------------------------------------------------------------------

Commission Determination
    73. The Commission will not adopt the optional market power screen 
for ancillary services as proposed in the NOPR. As suggested by EEI, 
ESPA and others, the fact that the proposed optional screen would not 
consider the full amount of competing supply available to a buyer 
likely means that the screen may result in so many false positive 
indications of potential market power that it would provide little 
benefit to the effort to foster competition in ancillary service 
markets.
    74. The comments also indicate that establishing the reporting 
requirements associated with the optional market power screen would not 
be a trivial task, particularly given the lack of consensus regarding 
the granularity of information needed. The Commission believes that the 
costs of developing and imposing this new reporting requirement on 
transmission providers might not be justified, particularly in light of 
the other actions taken in this Final Rule. The need for the proposed 
optional screen, and its associated reporting requirement, is 
significantly reduced because this Final Rule, as explained above, will 
permit sellers to apply the existing market power screens to imbalance 
and operating reserve ancillary services. As such, the Commission has 
determined not to adopt the optional market power screen and its 
associated reporting requirement.
Alternative Mitigation
    75. In the NOPR, the Commission proposed 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 transmission 
provider purchasing ancillary services to satisfy its OATT requirements 
to offer ancillary services to its own customers.\99\ Such a price cap 
would have been based on one of the two possible OATT ancillary service 
rate caps discussed below and, as in Avista, the Commission proposed 
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. In addition, 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.
---------------------------------------------------------------------------

    \99\ NOPR, FERC Stats. & Regs. ] 32,690 at PP 33-40.
---------------------------------------------------------------------------

Use of Price Caps
Commission Proposal
    76. In the NOPR, the Commission proposed two cost-based mitigation 
measures as alternatives to the prohibition adopted in Avista with 
regard to sales to a public utility transmission provider that is 
purchasing ancillary services to meet its OATT requirements to offer 
ancillary services to its own customers. Sales of ancillary services at 
or below either alternative would be permitted. Under the first, third 
parties would be permitted to sell to a public utility transmission 
provider at rates not to exceed the buying public utility transmission 
provider's existing OATT rate for the same ancillary service. Under the 
second option, third parties could propose to sell a given ancillary 
service to a public utility transmission provider 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. The Commission proposed that the seller 
(or group of sellers) would 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.
Single OATT Rate Cap Option
Comments
    77. There was a range of support for the establishment of a rate 
cap at the buyer's OATT rate for the same ancillary service. TAPS and 
Southern California Edison support this proposal outright as an option 
to enable ancillary service sales.\100\ EEI states that while the 
Commission should primarily rely on existing market power analyses and 
screens to allow third-parties to sell certain ancillary services at 
market-based rates, cost-based mitigation measures are also appropriate 
in certain seller-specific circumstances. EEI states that these two 
alternative options should be included in any Final Rule. EEI contends 
that this flexibility should encourage an increased number of 
participating sellers in bilateral markets, provide options for 
transmission providers to meet obligations, create market efficiencies, 
and potentially lower prices.\101\
---------------------------------------------------------------------------

    \100\ TAPS Comments at 15-18 and Southern California Edison 
Comments at 6.
    \101\ EEI Comments at 18-19.
---------------------------------------------------------------------------

    78. WSPP states that it supports inclusion of this option to 
enhance flexibility in the sale of ancillary services, but with 
reservations. WSPP's reservations essentially concern whether existing 
OATT ancillary services rates provide appropriate price signals. WSPP 
contends that because reserve sales are from the same units as energy 
sales, mitigation price caps that

[[Page 46190]]

fail to take opportunity costs into account during peak periods are 
unduly low.\102\ Separately, WSPP asks the Commission to clarify that 
for the single OATT rate cap there is no filing with the Commission as 
a prerequisite to the sale.\103\ AWEA and Solar Energy Association 
either support the proposal or do not state opposition to it.\104\ 
Iberdrola supports WSPP's and AWEA's comments by reference.\105\ 
Electricity Consumers state that they do not object to the proposed 
alternatives provided that they are in fact promulgated as alternatives 
to the proposed revisions to the market power analysis.\106\
---------------------------------------------------------------------------

    \102\ WSPP Comments at 15.
    \103\ Id. at 14.
    \104\ AWEA Comments at 3 and Solar Energy Association Comments 
at 6.
    \105\ Iberdrola Comments at 3.
    \106\ Electricity Consumers Comments at 4.
---------------------------------------------------------------------------

    79. Although ESA, Beacon, and California Storage Alliance all 
support this proposal, they each argue that for this mitigation measure 
to be successful in fostering robust competitive markets, the 
Commission must ensure that cost-based schedules for ancillary 
services, in particular Regulation and Frequency Response, are compared 
on an ``apples-to-apples'' basis taking into account resource 
performance.\107\
---------------------------------------------------------------------------

    \107\ ESA Comments at 8-10; Beacon Comments at 7-9; and 
California Storage Alliance Comments at 5-6.
---------------------------------------------------------------------------

    80. Some commenters oppose this price cap proposal unless the cap 
can be raised in some way. For example, Shell Energy argues that a cap 
based on the buyer's OATT rate would not produce prices high enough to 
entice competitive supply. Instead, Shell Energy suggests establishment 
of a price cap set at 200 percent of the buyer's OATT rate for the 
ancillary service in question.\108\ Similarly, EPSA asserts that cost-
based price caps systematically fail to represent the true value of 
capacity products and will fail to allow a full range of economic 
tradeoffs in the bilateral markets. EPSA states support for the use of 
price caps as a last resort, and only if they reflect the seller's lost 
opportunity costs as represented by energy transactions during a recent 
historical period.\109\ Powerex makes similar arguments, favoring the 
use of energy price indices to represent lost opportunity costs. 
Failing that, Powerex argues that a component for transmission costs 
for remote suppliers should be added to any OATT-based price cap.\110\
---------------------------------------------------------------------------

    \108\ Shell Energy Comments at 8-9.
    \109\ EPSA Comments at 9-10.
    \110\ Powerex Comments at 25-29.
---------------------------------------------------------------------------

    81. ENBALA argues that a cost-based cap limited to the buying 
utility's OATT rate might be too restrictive and lead the Commission to 
scrutinize more agreements than necessary, but ENBALA states that 
``Reactive Supply and Voltage Control service should be excluded from 
the regional price cap, being priced by the buying utility's OATT rate 
to reflect the geographic limitations of the ancillary service.'' \111\
---------------------------------------------------------------------------

    \111\ ENBALA Comments at 2-4.
---------------------------------------------------------------------------

Commission Determination
    82. As one option available to sellers, the Commission will permit 
market-based sales of Regulation and Frequency Response service and 
Reactive Supply and Voltage Control service to public utility 
transmission providers at rates not to exceed the buying public utility 
transmission provider's OATT rate for the same service.\112\ We find 
that a price cap based on the buying public utility transmission 
provider's OATT rate for the same ancillary service would produce a 
just and reasonable rate, and do so in a manner that is 
administratively simple. As discussed in the NOPR,\113\ because the 
buying public utility transmission provider's OATT ancillary service 
rates have already been found to be just and reasonable, it is 
reasonable to find that any third-party sales of the same ancillary 
service to that buyer at or below that buyer's own approved rates for 
that service would also be just and reasonable. Accordingly, we will 
not require sellers to make a separate showing as to the justness and 
reasonableness of such rates and will allow sellers to make third-party 
sales of such services at rates as discussed here as of the effective 
date of this Final Rule.
---------------------------------------------------------------------------

    \112\ We do not apply this mitigation option to the other OATT 
ancillary services because this Final Rule allows sales of those 
services at market-based rates for any seller that has market-based 
rate authority for energy and capacity.
    \113\ NOPR, FERC Stats. & Regs. ] 32,690 at P 34.
---------------------------------------------------------------------------

    83. Allowing the sale of ancillary services below the purchasing 
public utility transmission provider's OATT rate is a reasonable 
extension of the mitigation measure relied upon by the Avista policy 
itself. As discussed earlier,\114\ the Avista policy sought to protect 
buyers of third-party ancillary services from potential exercise of 
market power by ensuring that they would continue to have access to 
cost-based ancillary services from transmission providers, in effect 
limiting the price at which customers are willing to buy ancillary 
services from third-parties. The result of the Avista mitigation 
measure is an implicit soft cap on the price at which third-party 
ancillary services could be offered to non-transmission provider 
customers. The price cap proposal adopted here extends this concept to 
transmission providers by creating an explicit price cap at the same 
level.
---------------------------------------------------------------------------

    \114\ See supra P 7.
---------------------------------------------------------------------------

    84. While a few commenters opine that a cap based on the buyer's 
OATT rate would not produce prices high enough to entice competitive 
supply, the Commission finds that, given the reforms adopted elsewhere 
in this Final Rule, it is appropriate to take the more conservative 
step of adopting a price cap based on the buyer's OATT rate for sales 
of Regulation and Frequency Response service and Reactive Supply and 
Voltage Control service to public utility transmission providers. This 
measure can be implemented quickly and easily with few administrative 
burdens on either the Commission or the industry. Alternative proposals 
by commenters would require more complicated design, analysis, and 
oversight to ensure that they achieve just and reasonable rates.
    85. With respect to the arguments of ESA, Beacon, and California 
Storage Alliance that for this mitigation measure to be successful, the 
Commission must ensure that cost-based schedules for ancillary services 
are compared on an ``apples-to-apples'' basis taking into account 
resource performance, the Commission addresses this issue below in sub-
section B of this Final Rule.
Regional OATT Rate Cap Option
Comments
    86. Some commenters, such as ESA, Beacon, and the California 
Storage Alliance, support the regional OATT rate cap option on the 
basis that it is a reasonable approximation of the cost of entry.\115\ 
ENBALA also expresses support for a regional cost-based rate cap, 
arguing that it provides an adequate alternative to the current formal 
market power requirement.\116\ EEI and Electricity Consumers also 
express support for a regional OATT rate cap but offer no specific 
recommendations.\117\
---------------------------------------------------------------------------

    \115\ ESA Comments at 10; California Storage Alliance Comments 
at 7; and Beacon Comments at 9.
    \116\ ENBALA Comments at 2.
    \117\ EEI Comments at 18-19; and Electricity Consumers Comments 
at 4.
---------------------------------------------------------------------------

    87. Southern California Edison states that it supports a cap based 
on the highest OATT rate within the geographic market as long as it is 
capped at the lesser of (a) the highest OATT rate in the market or (b) 
three times the median OATT rate in the relevant geographic market. 
Southern

[[Page 46191]]

California Edison explains that it proposes this modification to 
protect against having a small balancing authority area with an 
extremely high outlier rate setting the cap.\118\
---------------------------------------------------------------------------

    \118\ Southern California Edison Comments at 6-7.
---------------------------------------------------------------------------

    88. Other commenters criticize the highest OATT rate cap proposal. 
Some parties, such as WSPP, EPSA, and Powerex, argue that setting caps 
based on cost-based rates would not allow sellers to recover foregone 
opportunity costs associated with energy sales and thus would fail to 
create any incentives for sellers to enter ancillary service markets. 
They argue that this is particularly true for short-term ancillary 
service sales, given that opportunity costs vary materially for hourly, 
daily, monthly, and seasonal periods, but these variations are not 
reflected in OATT rates and therefore would not be reflected in the 
cap.
    89. For example, Powerex contends that any alternative price cap 
must be high enough to create economic incentives for potential sellers 
to forego other opportunities, namely, energy sales.\119\ Powerex 
argues that setting price caps based on transmission providers' cost-
based rates in many instances will not allow sellers to recover the 
foregone opportunity costs associated with energy sales and that this 
is particularly true for short-term ancillary service sales.\120\ 
Powerex states that short-term energy prices in the CAISO and other 
Western markets are frequently several-fold higher than Northwest 
transmission providers' OATT rates for ancillary services.\121\
---------------------------------------------------------------------------

    \119\ Powerex Comments at 26.
    \120\ Id.
    \121\ Id. at 27.
---------------------------------------------------------------------------

    90. Similarly, EPSA argues that a price cap should include a 
seller's lost opportunity costs, represented by energy transactions 
during a recent historical period. EPSA states that it is critically 
important to include lost opportunity costs, in order to allow a 
generator to rationally choose between producing energy and not 
producing energy.\122\
---------------------------------------------------------------------------

    \122\ EPSA Comments at 9-10.
---------------------------------------------------------------------------

    91. WSPP asserts that the Commission's observation that the OATT 
rate could be indicative of the cost of new entry appears speculative. 
WSPP contends that a cost-based rate may reflect a fully or 
substantially depreciated unit, rather than the cost of new 
construction.\123\ WSPP also argues that because reserve sales are made 
from the same resources as energy sales, mitigation price caps that 
fail to take opportunity costs into account during peak periods are 
unduly low.\124\
---------------------------------------------------------------------------

    \123\ WSPP Comments at 15.
    \124\ Id. at 15.
---------------------------------------------------------------------------

    92. Other commenters raise concerns about setting the geographic 
boundaries for a regional OATT rate cap. Shell Energy asserts that 
identifying the region in which an ancillary service can be physically 
traded can be difficult and recommends that the Commission, rather than 
sellers, identify the relevant trading regions and post that 
information on the Commission's Web site.\125\ TAPS argues that a 
regional price cap would invite gerrymandering and provide no assurance 
that the resulting cap is a more reasonable approximation of the cost 
of new entry.\126\ TAPS argues that significant physical constraints 
limit the provision of ancillary services over a geographic area.\127\ 
TAPS contends that the regional OATT rate cap proposal is not 
defensible as either a cost-based or market-based rate and is at odds 
with the physical limitations on the provision of ancillary services in 
non-RTO regions.\128\ TAPS contends that another regional transmission 
provider's higher rate (i.e., the highest regional rate) does not bear 
any relationship to either a third-party supplier's or the purchasing 
transmission provider's cost of supply.\129\
---------------------------------------------------------------------------

    \125\ Shell Energy Comments at 9.
    \126\ TAPS Comments at 22.
    \127\ Id. at 20.
    \128\ Id. at 2.
    \129\ Id. at 19.
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Commission Determination
    93. The Commission will not adopt the NOPR proposal that would 
allow sellers to propose a price cap equal to the highest OATT rate 
within a specified region. Based on the comments received, the 
Commission concludes that use of a regional OATT rate cap would be 
inadequate to ensure that third-party sellers' rates remain just and 
reasonable. In the NOPR, the Commission suggested that this mitigation 
proposal might be justified on a cost basis in that the highest 
regional rate may be a reasonable approximation of the cost of new 
entry into the region in question.\130\ However, the record developed 
in this proceeding does not support such a conclusion at this time.
---------------------------------------------------------------------------

    \130\ NOPR, FERC Stats. & Regs. ] 32,690 at P 36.
---------------------------------------------------------------------------

    94. We also share commenters' concerns associated with defining 
appropriate regions for purposes of setting regional price caps. The 
Commission is concerned that sellers would have an incentive to 
``gerrymander'' or ``cherry-pick'' regional definitions to ensure 
inclusion of a high-cost ancillary service provider. In light of the 
other actions taken in this Final Rule, the Commission believes it 
would not be productive to undertake the analyses necessary to 
establish seller-specific regions for various ancillary services.
Competitive Solicitations
Commission Proposal
    95. The NOPR proposed 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 guidelines: (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; (4) 
oversight--an independent third-party should design the solicitation, 
administer bidding, and evaluate bids prior to the company's 
selection;\131\ and (5) competitiveness--adequate seller interest to 
ensure competitiveness.
---------------------------------------------------------------------------

    \131\ See, e.g., Allegheny Energy Supply Co. LLC, 108 FERC ] 
61,082 (2004).
---------------------------------------------------------------------------

Comments
    96. Commenters generally support the proposal to permit competitive 
solicitations as an alternative to performing a market power 
study.\132\ EEI, for example, expresses support for competitive 
procurement as an option for long-term resource planning.\133\ EPSA 
states that the Commission's proposed guidelines for competitive 
solicitations conform to general principles that EPSA has advocated for 
such processes.\134\
---------------------------------------------------------------------------

    \132\ EPSA Comments at 8-9; EEI Comments at 19-20; ESA Comments 
at 10-11; Beacon Comments at 9-11; California Storage Alliance 
Comments at 7; and ENBALA Comments at 4.
    \133\ EEI Comments at 19-20.
    \134\ EPSA Comments at 8-9.
---------------------------------------------------------------------------

    97. Some commenters object to certain aspects of the Commission's 
proposal. Most criticism is directed at the proposed requirement for 
independent third-party oversight of competitive solicitations. WSPP, 
for example, expresses support for competitive solicitations as a means 
of mitigating potential market power concerns but opposes the proposed 
oversight by an independent third party. WSPP argues that such 
oversight is unnecessary, and that the required filing

[[Page 46192]]

is ample to demonstrate whether or not the solicitation yielded 
sufficient competition.\135\ Shell Energy agrees that third-party 
oversight of competitive solicitations is unnecessary, arguing that 
this requirement would hinder short-term procurement of ancillary 
services and make the solicitation process unfeasible except for long-
term transactions.\136\
---------------------------------------------------------------------------

    \135\ WSPP Comments at 17-18.
    \136\ Shell Energy Comments at 10.
---------------------------------------------------------------------------

    98. However, Morgan Stanley contends that it is not clear that the 
Commission's competitive solicitation proposal would protect against 
market power. Morgan Stanley contends that a competitive solicitation 
only demonstrates lack of market power if it is robust enough to 
attract offers that, in aggregate, are significantly in excess of the 
quantity sought. Morgan Stanley states that it is not clear how a 
competitive solicitation could help buyers looking to purchase such 
services on a short-term basis, although it might for the long-term 
provision of ancillary services.\137\
---------------------------------------------------------------------------

    \137\ Morgan Stanley Comments at 8-9.
---------------------------------------------------------------------------

Commission Determination
    99. The Commission adopts the NOPR proposal to allow applicants to 
engage in market-based sales of ancillary services to a public utility 
that is purchasing ancillary services to satisfy its OATT requirements 
where the sale is made pursuant to a competitive solicitation that 
meets the requirements specified in the NOPR as numerated above, except 
as modified below. The Commission has relied on the use of competitive 
solicitations to mitigate affiliate abuse concerns when affiliates seek 
to enter into transactions pursuant to market-based rate 
authority.\138\ In that context, the Commission has adopted guidelines 
for independent, third-party review of competitive solicitations. The 
requirements proposed for sales of ancillary services to public utility 
transmission providers are based on these guidelines, which the 
Commission concludes are reasonable to adopt here with one exception. 
Upon review of comments, we have decided to partially eliminate the 
requirement that an independent third-party design and administer the 
solicitation and evaluate bids prior to the company's selection.
---------------------------------------------------------------------------

    \138\ See Boston Edison Co. Re: Edgar Electric Energy Co., 55 
FERC ] 61,382 (1991); Allegheny, 108 FERC ] 61,082.
---------------------------------------------------------------------------

    100. As proposed, the independent third-party review requirement 
would apply to all competitive solicitations. However, the record does 
not support imposing a requirement for independent third-party review 
when none of the parties participating in a competitive solicitation is 
affiliated with the buying public utility transmission provider. If no 
affiliate of the buyer participates in the solicitation, there is no 
concern regarding preferential treatment and, therefore, no need for 
review by an independent third party. As commenters suggest, requiring 
an independent third-party reviewer could discourage the use of 
competitive solicitations as it would add to the cost and time needed 
to procure ancillary services. Some public utility buyers may have a 
short-term, unexpected need for ancillary services and therefore need 
to act quickly to fill this need. In such cases, the buyer itself will 
have to conduct the solicitation, with very limited time for 
independent review. The Commission therefore revises the NOPR proposal 
to require independent third-party review of competitive solicitations 
only when the buyer solicits offers from one or more of its affiliates.
    101. However, the Commission emphasizes that any buyer seeking to 
procure ancillary services from unaffiliated sellers through a 
competitive solicitation will need to demonstrate compliance with the 
four other requirements: transparency, definition, evaluation, and 
competitiveness. In this regard, we reject Morgan Stanley's assertion 
that the competitiveness requirement can only be met where a 
solicitation attracts offers that, in aggregate, are significantly in 
excess of the quantity sought. We believe there may be multiple methods 
of demonstrating adequate competitiveness, and we will review such 
proposals on a case-by-case basis. This will help ensure that any 
ancillary services procured in this manner are purchased at a 
competitive market price. At the same time, these requirements will not 
hinder buyers' flexibility to design solicitations to meet their 
specific needs. This demonstration must be made through a filing under 
section 205 of the Federal Power Act, submitted by the seller to the 
Commission prior to commencement of service under the third-party 
ancillary service sales agreement that results from the competitive 
solicitation. To be specific, the third-party seller will need to 
submit both the actual sales agreement and a narrative description of 
how the buyer's competitive solicitation meets the requirements of this 
Final Rule. This narrative description will help demonstrate that 
exercise of market power was not a factor in the negotiation of the 
sales agreement, and therefore that the resulting rate is just and 
reasonable.

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

Commission Proposal
    102. The Commission proposed in the NOPR 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. Among other things, this would allow customers choosing 
to self-supply this service with faster responding or more accurate 
resources to self-supply with a lower volume of regulation capacity, or 
vice versa. The Commission stated that it expects to evaluate each 
proposed determination of regulation reserve requirements on a case-by-
case basis. It also stated that each description of how the public 
utility will adjust its regulation capacity requirement must provide 
enough detail that an entity wishing to self-supply may compare the 
resources it is considering using with the resources that the public 
utility is using. The Commission sought comment on how speed and 
accuracy should be taken into account.\139\
---------------------------------------------------------------------------

    \139\ NOPR, FERC Stats. & Regs. ] 32,690 at PP 47-54.
---------------------------------------------------------------------------

Comments
    103. A majority of commenters\140\ generally support the NOPR 
proposal to require each public utility transmission provider to 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. Electricity Consumers, Hydro 
Association, Morgan Stanley, California PUC, and EPSA highlight the 
benefits of increased transparency, to which EPSA adds that lack of 
transparency is an impediment to competitive compensation outside of 
ISOs/RTOs and contributes to a lack of a discernible market value for 
speed and accuracy. Other commenters, including Public Interest 
Organizations, Iberdrola, Morgan Stanley, and FTC Staff cite avoidance 
of undue discrimination, comparable treatment, and the potential that 
the NOPR proposal will encourage innovation and new entry, as reasons 
for

[[Page 46193]]

supporting the proposal. Solar Energy Association supports taking into 
account the speed and accuracy of regulation resources when 
establishing the rates that may be charged for those services, with 
faster and more accurate resources priced accordingly.\141\
---------------------------------------------------------------------------

    \140\ These commenters include Beacon, California Storage 
Alliance, ESA, Hydro Association, Solar Energy Association, Public 
Interest Organizations, California PUC, AWEA, Morgan Stanley, EPSA, 
TAPS, FTC Staff, Electricity Consumers, and Iberdrola.
    \141\ Solar Industry Association Comments at 3.
---------------------------------------------------------------------------

    104. Hydro Association supports the idea of ``pay for performance'' 
standards that recognize the difference between accurate fast-
responding resources versus resources that ramp more slowly and respond 
less nimbly, and agrees with the Commission that a case-by-case 
evaluation of each proposed determination is more appropriate than 
imposing a mandatory methodology. Similarly, California PUC states that 
transparency should act as a deterrent against discrimination, but 
cautions that the Commission should avoid an overly prescriptive 
methodology that may dictate the amount of regulation resources that 
are needed.
    105. Several other commenters, including Beacon, ESA, California 
Storage Alliance, and Morgan Stanley, encourage the Commission to 
require transmission providers to provide an explanation of how they 
set their regulation reserve requirements. ESA, Beacon, and California 
Storage Alliance propose five elements of an explanation that each 
transmission provider should be required to provide about how it sets 
its regulation reserve requirement,\142\ as well as a list of specific 
information that each transmission provider should make available.\143\ 
Morgan Stanley also urges the Commission to require public utility 
transmission providers to provide demonstrations of equivalent 
treatment for their own or their affiliate's requirements to ensure 
that there is no undue discrimination, and to establish a process for 
market participants to challenge and resolve the speed and accuracy 
assumptions and requirements that public utility transmission providers 
publish.\144\ Beacon and ESA also state that ideally the Commission 
would require each utility to develop a conversion formula or chart 
that specifies how much capacity a transmission customer must self-
supply given a certain ramp-rate and accuracy.
---------------------------------------------------------------------------

    \142\ The five elements are: (1) A description of the 
calculation; (2) the metric which is used to set the requirement; 
(3) the average performance of the existing Regulation assets; (4) 
the speed and accuracy of the units currently in place (including 
ramp-rate and accuracy); and (5) sufficient data for a third party 
to reproduce the results, including posting ACE data on its OASIS 
reporting. ESA Comments at 12-13; Beacon Comments at 12; and 
California Storage Alliance Comments at 6.
    \143\ Each entity proposes a bulleted list of nine items 
including generation capacity available to provide regulation, 
rates, costs, accuracy and CPS scores, and representative ACE data. 
ESA Comments at 13; and Beacon Comments at 12-13.
    \144\ Morgan Stanley Comments at 10.
---------------------------------------------------------------------------

    106. ESA, Beacon, Public Interest Organizations, California Storage 
Alliance, and AWEA advocate extending the requirement of accounting for 
speed and accuracy in regulation service to public utilities meeting 
their own needs, including via third-party suppliers, not simply to 
transmission customers choosing to self-supply.\145\ AWEA argues that 
holding more reserves than needed may result in rates that are not just 
and reasonable.\146\ ESA, Beacon, Public Interest Organizations, and 
California Storage Alliance state that third party sales to a public 
utility that is purchasing ancillary services to satisfy its own OATT 
requirements to offer ancillary services to its own customers 
represents the most significant potential market for sales of ancillary 
services in non-RTO/ISO regions. Public Interest Organizations agree, 
arguing that neither the current rules nor the NOPR encourage 
transmission providers to improve the speed and accuracy of their owned 
or contracted frequency regulation resources, and that allowing 
generators to be displaced from providing frequency regulation will 
enable them to operate at a more stable output, which also can lower 
energy market prices. Public Interest Organizations contend that the 
existing OATT Schedule 3 rate treatment is no longer adequate to 
incorporate emerging technologies, and encourage the Commission to 
require that OATT Schedule 3 rates incorporate Order No. 755's 
framework of an objective accuracy and performance determination, and 
that the amount of frequency regulation transmission customers are 
required to procure or self-supply takes into account the speed and 
accuracy capability of the ancillary service provider's 
technology.\147\
---------------------------------------------------------------------------

    \145\ Beacon and Public Interest Organizations support ESA's 
comments regarding third party sales of regulation.
    \146\ AWEA Comments at 4.
    \147\ Public Interest Organizations Comments at 8.
---------------------------------------------------------------------------

    107. Parties that support extending the proposal to public utility 
transmission providers meeting their own needs also recommend that the 
Commission consider performance-based rate treatment for public utility 
investments and contracts with third-party ancillary service providers 
that allow the public utility to reduce the total capacity and cost of 
providing regulation service while maintaining the same level of 
reliability.\148\ They argue that the potential benefits to ratepayers 
could justify allowing a performance-based incentive rate adder that 
public utility transmission providers could recover through rates, and 
that if the public utility can demonstrate that it will be able to 
reduce the total capacity and cost of providing regulation service and 
maintain the same degree of reliability, such treatment should result 
in public utilities improving the performance of their regulation fleet 
and in turn reducing expenses for frequency regulation, ultimately 
resulting in lower costs.
---------------------------------------------------------------------------

    \148\ See comments of ESA, Beacon, Public Interest 
Organizations, and California Storage Alliance.
---------------------------------------------------------------------------

    108. TAPS asks the Commission to state explicitly that the NOPR's 
proposal to account for the speed and accuracy of customer self-
supplied regulating resources includes demand resources and to state 
that such a finding would be consistent with OATT Schedule 3 and Order 
No. 755.\149\
---------------------------------------------------------------------------

    \149\ TAPS Comments at 27.
---------------------------------------------------------------------------

    109. EEI opposes the NOPR proposal. It contends that it is 
premature to require each transmission provider to include provisions 
in its OATT explaining how it will determine Regulation and Frequency 
Response requirements, and requests that the Commission defer this 
proposal pending experience with secondary frequency control (i.e., 
regulation) in the ISOs and RTOs following the issuance of Order No. 
755.\150\ EEI requests that the Commission recognize the material 
differences between primary and secondary frequency control resources 
in the final rule. It argues that it is also premature to adopt 
requirements regarding primary frequency control, and recommends that 
the Commission encourage each balancing authority to continue 
investigating the role of various types of resources, and allow the 
industry to maintain its efforts to understand the relationship and 
interdependencies between primary and secondary frequency response.
---------------------------------------------------------------------------

    \150\ EEI Comments at 22-26.
---------------------------------------------------------------------------

    110. EEI contends that the assumption that faster responding 
technologies are necessarily more efficient than traditional methods of 
frequency regulation has not been substantiated. EEI explains that 
industry is still exploring frequency response, including current and 
historical primary and secondary control response performance, and that 
for system reliability it is important to maintain a balanced portfolio 
of resources including inertial response, governor response, and 
secondary frequency control (or regulation response). It further 
explains that, although OATT Schedule 3 groups primary and secondary 
frequency control into a single service, the nature of these

[[Page 46194]]

services are distinct. With regard to secondary frequency control 
(regulation), EEI claims that the benefits from resources that ramp 
more quickly for purposes of secondary frequency control may be offset 
by a lack of capability to sustain that response, or to provide 
automatic primary frequency control.
Commission Determination
    111. The Commission will adopt the NOPR proposal with modification. 
Rather than requiring OATT Schedule 3 to include a description of how 
resource speed and accuracy will be taken into account in determining 
Regulation and Frequency Response reserve requirements, we will require 
each public utility transmission provider to add to its OATT Schedule 3 
a statement that it will take into account the speed and accuracy of 
regulation resources in its determination of reserve requirements for 
Regulation and Frequency Response service, including as it reviews 
whether a self-supplying customer has made ``alternative comparable 
arrangements'' as required by the Schedule. This statement will also 
acknowledge that, upon request by the self-supplying customer, the 
public utility transmission provider will share with the customer its 
reasoning and any related data used to make the determination of 
whether the customer has made ``alternative comparable arrangements.'' 
\151\ To aid the transmission customer's ability to make an ``apples-
to-apples'' comparison of regulation resources, the Commission will 
also amend Part 35 of its Regulations by adding a new section (k) to 
Sec.  37.6,\152\ to require each public utility transmission provider 
to post certain Area Control Error (ACE) data described further below. 
We find that these reforms are necessary to address the potential for 
undue discrimination in the provision of Regulation and Frequency 
Response, including in instances when a customer self-supplies this 
service using its own resources or purchases from a third-party. 
Acknowledging the speed and accuracy of the resources used to provide 
this service will help to ensure that an appropriate quantity of 
resources is utilized for self-supply, whether those resources are 
faster and more accurate or slower and less accurate than those used by 
the public utility transmission provider. The weight of comments 
support reform in this area, including arguments that such a reform 
will help foster innovation and the entry of newer resources into the 
market.
---------------------------------------------------------------------------

    \151\ See Appendix B for the revised Schedule 3 of the pro forma 
OATT provisions consistent with this Final Rule.
    \152\ This regulation will replace the like-numbered proposed 
regulation related to historical ancillary service requirements data 
posting from the NOPR that we decline to adopt in section II.A.1.b. 
of this Final Rule.
---------------------------------------------------------------------------

    112. Under the current pro forma OATT, transmission customers 
considering using their own or third-party resources to self-supply 
regulation service are required to demonstrate to the public utility 
transmission provider that they have made ``alternative comparable 
arrangements.'' However, the pro forma OATT provides no further 
information as to how the determination of ``alternative comparable 
arrangements'' would be made. Moreover, the OATT contains no express 
obligation on the part of the transmission provider to consider the 
relative speed and accuracy of resources a customer might desire to use 
in self-supplying Regulation and Frequency Response service. A public 
utility transmission provider could require a customer seeking to self-
supply regulation services to provide a volume of regulation reserves 
based on the characteristics of the resources used by the public 
utility transmission provider to provide regulation service, which may 
not be reflective of the characteristics of the customer's resources. 
This could under- or overstate regulation reserve requirements 
depending on the relative characteristics of the resources at issue. It 
also could impair the customer's ability to self-supply regulation 
requirements at the lowest possible cost.\153\ The Commission finds 
that this lack of clarity as to the role of resource speed and accuracy 
in the determination of ``alternative comparable arrangements'' for 
regulation reserve requirements for self-supplying transmission 
customers must be addressed in order to limit opportunities for 
potential discrimination in the provision of regulation service by 
public utility transmission providers.
---------------------------------------------------------------------------

    \153\ For example, a self-supplying customer could save money 
either by relying on a smaller amount of high quality regulation 
resources at a slightly higher per-unit price or by relying on a 
larger amount of lower quality regulation resources at a much lower 
per-unit price. Provided that reliability is maintained, the 
transmission customer should have the ability to self-supply 
consistent with its preferences.
---------------------------------------------------------------------------

    113. While the Commission initially proposed that each public 
utility transmission provider should amend its OATT to include a 
description of how regulation reserve requirement determinations would 
take into account speed and accuracy of resources, we believe the 
better course of action at this time is to place the obligation on the 
public utility transmission provider to take into account speed and 
accuracy without requiring it to develop detailed tariff language 
describing the specific process to be used. This will provide the 
public utility transmission provider with flexibility while also 
providing the customer with information. While a number of commenters 
suggested elements for what the public utility transmission provider 
should be required to provide, the clearest proposal in the comments 
related to this issue request that public utility transmission 
providers be required to provide current monthly and 12-month rolling 
average Control Performance Standard 1 (CPS1), Control Performance 
Standard 2 (CPS2) and Balancing Authority ACE Limit (BAAL) scores for 
Frequency Regulation.\154\ However, by itself availability of such 
information would do nothing to explain how the public utility 
transmission provider determines regulation reserve amounts. 
Furthermore, while ACE information might help to characterize the speed 
and accuracy of the public utility transmission provider's own 
regulation resources, the Commission believes that using the relatively 
long duration of monthly and 12-month rolling ACE averages implicit in 
these scores may not provide information useful for measuring 
performance over a fraction of an hour, which is the relevant time 
frame for Regulation and Frequency Response service.
---------------------------------------------------------------------------

    \154\ CPS1 and CPS2 are described in NERC Reliability Standard 
BAL-001-0.1a--Real Power Balancing Control Performance. The BAAL 
criterion is expected to replace CPS2 in that Reliability Standard 
when it becomes effective, pending final approval by NERC and the 
Commission.
---------------------------------------------------------------------------

    114. Accordingly, the Commission declines to impose a ``one size 
fits all'' approach to calculating regulation reserve requirements, 
consistent with the comments of Hydro Association and California PUC, 
and declines to require the inclusion of this process in Schedule 3. 
Rather, we require that Schedule 3 be amended to include a statement 
that the public utility transmission provider will take into account 
the speed and accuracy of regulation resources in determining reserve 
requirements for Regulation and Frequency Response service, including 
when reviewing whether a self-supplying customer has made ``alternative 
comparable arrangements.'' Self-supplying customers and their public 
utility transmission providers will then have a basis to study and 
negotiate appropriate arrangements case-by-case, very similar to how 
such

[[Page 46195]]

interactions take place under other processes such as the 
interconnection process.
    115. That said, we agree with the comments of ESA, Beacon, and 
California Storage Alliance that transmission customers considering 
whether or not there would be any economic advantage to self-supply of 
Regulation and Frequency Response service requirements would need to be 
able to make an ``apples-to-apples'' comparison of their resources to 
those of their public utility transmission provider.\155\ Doing so 
would require the transmission customer to know both the potential 
avoided cost of purchasing from its public utility transmission 
provider, and some measure of the speed and accuracy of the public 
utility transmission provider's Regulation resources. The first 
requirement is met through the rate filed in the public utility 
transmission provider's OATT Schedule 3. We believe the second 
requirement can only be met through a new OASIS posting requirement.
---------------------------------------------------------------------------

    \155\ ESA Comments at 8-10; Beacon Comments at 7-9; and 
California Storage Alliance Comments at 5-6.
---------------------------------------------------------------------------

    116. As noted earlier, the public utility transmission provider's 
CPS1, CPS2, and BAAL scores might address this need in concept, except 
that they currently reflect long-term averages that do not match the 
relevant time frame for Regulation and Frequency Response service. We 
believe the one-minute and ten-minute average ACE data collected by 
public utility transmission providers to produce the CPS1, CPS2, and 
BAAL scores would be more useful for this purpose because it does match 
the relevant time frame. Accordingly, in order to ensure a level of 
transparency adequate to support self-supply decision-making by 
transmission customers, we will require public utility transmission 
providers to post historical one-minute and ten-minute ACE data on 
OASIS. For this purpose, we find that historical data for the most 
recent calendar year, updated once per year, should meet the need. This 
information is already collected and provided to NERC, through 
balancing area operators and reliability coordinators, so there should 
be minimal incremental burden associated with posting it on OASIS.
    117. The Commission's standard filing requirements, including 
opportunity for intervention and comment, address Morgan Stanley's 
request to establish a process for market participants to challenge and 
resolve speed and accuracy assumptions. For example, as is the case in 
interconnection agreement proceedings, the transmission service 
agreement that reflects an individually negotiated self-supply 
arrangement for Regulation and Frequency Response service can be filed 
by the public utility transmission provider unexecuted. This will leave 
the transmission customer free to protest relevant aspects of the 
public utility transmission provider's determination of whether the 
customer has made ``alternative comparable arrangements,'' including as 
those arrangements relate to the speed and accuracy of the customer's 
proposed Regulation resources.
    118. With respect to Morgan Stanley's request that public utilities 
demonstrate equivalent treatment for their own or their affiliate's 
regulation requirements, we find that the increased transparency 
required by this Final Rule will accomplish this goal. The requirements 
adopted above apply to the public utility transmission provider's own 
regulation resources, in the sense that it must apply the same 
procedures for determining regulation reserve requirements to itself as 
it does to self-supplying customers.
    119. With respect to the request of TAPS that the Commission state 
explicitly that the NOPR's proposal to account for the speed and 
accuracy of customer self-supplied regulating resources includes demand 
resources, we note that OATT Schedule 3, as amended by Order No. 890 
makes clear that Regulation and Frequency Response service may be 
provided from non-generation resources capable of providing the 
service. Accordingly, a transmission provider's determination of 
regulation reserve requirements should take into account the speed and 
accuracy characteristics of the resources in question, whether they are 
generation-based or otherwise.
    120. Turning to the various requests that the Commission step 
beyond the NOPR proposals, the Commission declines to require two-part 
pricing for regulation capacity and performance set forth in Order No. 
755. We conclude that the requirements adopted above will allow 
customers and the Commission to ensure that the speed and accuracy of 
resources used for regulation reserves are properly taken into account 
in reserve level determinations within the context of the bilateral 
markets within which non-RTO/ISO public utility transmission providers 
operate. The Commission also declines commenter requests to provide 
incentive rate treatment for purchases of Regulation and Frequency 
Response service by public utility transmission providers to meet their 
OATT requirements. Commenters are not clear as to what mechanism they 
believe the Commission should use to require such treatment, and the 
Commission sees no reason to implement an incentives program in the 
context of ancillary services rate design.
    121. With respect to EEI's comments regarding differences between 
primary frequency response and secondary frequency regulation, the 
Commission acknowledges these distinctions. Improving the transparency 
regarding the resources used to provide Regulation and Frequency 
Response service under OATT Schedule 3 does not alter the ability of 
any balancing authority to maintain adequate reserves to meet 
reliability requirements. The Commission thus sees no need to wait for 
the industry to better understand the relationship and 
interdependencies between primary and secondary frequency response 
prior to adopting the requirements of this final rule. The Commission 
will evaluate a public utility transmission provider's compliance 
proposal as part of the case-by-case review discussed above, which will 
provide the public utility transmission provider the opportunity to 
demonstrate how it establishes its regulation reserve requirements.

Accounting and Reporting for Energy Storage Operations

    122. In the NOPR, the Commission proposed to revise certain 
accounting and reporting requirements under its USofA and its forms, 
statements, and reports contained in Form Nos. 1, 1-F, and 3-Q. The 
Commission stated that the revisions were needed so that entities 
subject to the Commission's accounting and reporting requirements could 
better account for and report transactions associated with energy 
storage devices used in public utility operations. Moreover, the 
Commission noted that 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 subject to the accounting and reporting 
requirements.
    123. The Commission proposed that new electric plant and associated 
O&M expense accounts be created to provide for the recording of 
investment and O&M costs of energy storage assets. The Commission also 
proposed to create a new purchased power account to provide for 
recording the cost of power purchased for use in storage operations. In 
addition, the Commission proposed that new Form Nos. 1 and 1-F 
schedules be created and existing schedules in the forms and Form No. 
3-

[[Page 46196]]

Q be amended to report operational and statistical data on storage 
assets. Finally, the Commission inquired about whether entities seeking 
to recover costs of energy storage assets and operations simultaneously 
under cost-based and market-based rates should be required to forego 
previously granted accounting and reporting waivers associated with 
market-based rates, and if so, should the requirement to forego the 
waivers be subject to some percentage threshold based on a ratio of 
cost-based cost recovery to total cost to be recovered.
    124. While most commenters support the Commission's proposal to 
revise the accounting and reporting requirements, there were several 
recommendations to make adjustments to the proposals and also requests 
for clarification of certain proposals. Only Solar Energy Association 
opposed the proposal, stating, without elaboration, that it believes it 
is premature to establish reporting requirements for energy 
storage.\156\ In the NOPR, the Commission responded to similar 
arguments regarding maturity of the energy storage industry as it 
relates to the use of energy storage assets to provide public utility 
services, and found those arguments unconvincing.\157\ The Commission 
explained that there is a need for certainty in the accounting and 
reporting treatment for energy storage assets and operations, 
especially in instances where utilities seek to recover costs of energy 
storage operations in cost-based rates. Solar Energy Association has 
not provided new information that we could consider on this issue, 
therefore we find Solar Energy Association's argument unconvincing.
---------------------------------------------------------------------------

    \156\ Solar Energy Association Comments at 7.
    \157\ NOPR, FERC Stats. & Regs. ] 32,690 at P 71.
---------------------------------------------------------------------------

1. Electric Plant Accounts
Commission Proposal
    125. In the NOPR, the Commission stated that the existing primary 
plant accounts do not explicitly provide for recording the cost of 
energy storage assets. The Commission concluded that this could 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. The Commission 
also noted that the lack of transparency affects interested parties', 
including the Commission's, ability to monitor these utilities' 
operations to prevent and discourage cross-subsidization between cost-
based and market-based activities. To address these issues, the 
Commission proposed to create electric plant accounts in the existing 
functional classifications--production, transmission, and 
distribution--for new energy storage assets.\158\
---------------------------------------------------------------------------

    \158\ Account 348, Energy Storage Equipment-Production; Account 
351, Energy Storage Equipment--Transmission; and Account 363, Energy 
Storage Equipment--Distribution, respectively.
---------------------------------------------------------------------------

    126. The Commission proposed that the installed costs of energy 
storage assets be recorded in the accounts based on the function or 
purpose the asset serves. On this basis, an asset that performs a 
single function will have its cost recorded in a single plant account. 
In instances where an energy storage asset is used to perform more than 
one function or purpose, the Commission proposed that the cost of the 
asset be allocated among the relevant energy storage plant accounts 
based on the functions performed by the asset and the allocation of the 
asset's costs through cost-based rates that are approved by a relevant 
regulatory agency, whether federal or state.\159\
---------------------------------------------------------------------------

    \159\ NOPR, FERC Stats. & Regs. ] 32,690 at P 81.
---------------------------------------------------------------------------

Comments
    127. In general, the commenters applaud the Commission's efforts to 
improve transparency and prevent double-recovery of energy storage-
related costs. The proposal to require utilities to record the costs of 
single-function energy storage assets in a single plant account 
garnered widespread support. However, the proposal to require utilities 
to allocate the costs of multi-function energy storage assets to the 
relevant energy storage plant accounts based on the functions performed 
and approved rate recovery, received comments supporting and opposing 
the proposal. Commenters that agree with the proposal generally 
indicate that the accounting would provide necessary transparency of a 
utility's operations,\160\ while commenters that oppose the proposal 
generally indicate that the accounting would place an undue 
administrative burden on utilities and is inconsistent with the 
Commission's existing accounting rules.\161\
---------------------------------------------------------------------------

    \160\ Public Interest Organizations Comments at 9-10; California 
PUC Comments at 9; NU Companies Comments at 4; APPA Comments at 5; 
ESA Comments at 18-19; TAPS Comments at 28-29; and California 
Storage Association Comments at 11-12.
    \161\ Southern California Edison Comments at 8; SDG&E Comments 
at 2-3; and EEI Comments at 29-30.
---------------------------------------------------------------------------

    128. Public Interest Organizations state that they support the 
development of requirements that can reveal the activities and costs of 
energy storage operations thorough greater transparency and detail. 
California PUC similarly states that in the event an energy storage 
developer intends to use a facility to perform multiple functions, the 
proposed accounting and reporting should provide transparency. NU 
Companies state that they support flexible rate treatment for energy 
storage assets and believe the proposed accounting will provide 
transparency required to guard against inappropriate cross 
subsidization of various services and double recovery cost.
    129. In opposition to the proposal, SDG&E contends that while it 
generally agrees with the Commission's allocation ``concept'' to 
account for energy storage assets by functional category, i.e., 
production, transmission, and distribution, it is concerned that 
generally applicable financial tools may not be able to efficiently 
track or monitor up to three functional categories for one asset 
without increased and ongoing manual intervention.\162\ SDG&E argues 
that it agrees that the initial allocation concept would capture 
expenses by each function as the Commission intends; however, if the 
utility subsequently changes its initial allocation in the future the 
proposed accounting would create an unnecessary administrative burden 
that if a mistake is made could result in costs of the asset being 
stranded. SDG&E contends that to ensure the asset is accounted for 
properly so that asset costs are not stranded, a utility would be 
required to continuously monitor the asset to make sure its initial 
allocation is consistent with the asset's actual usage. SDG&E 
acknowledges that the NOPR addresses this concern; \163\ however, SDG&E 
asserts that there is a more straightforward approach that can be used 
to allocate the costs of a multi-function energy storage asset. SDG&E 
advocates, instead of using multiple plant accounts, that the cost of 
an energy storage asset be recorded in a single plant account and its 
cost allocated to the various functions it performs using current 
ratemaking methods.
---------------------------------------------------------------------------

    \162\ SDG&E Comments at 2-3.
    \163\ SDG&E cites to the NOPR proposal that a utility transfer 
reallocated cost of an energy storage asset in accordance with the 
instructions of Electric Plant Instruction No. 12, Transfers of 
Property, 18 CFR Part 101 (2012). See SDG&E Comments at 3-4 (citing 
to NOPR, FERC Stats. & Regs. ] 32,690 at P 82).
---------------------------------------------------------------------------

    130. Similar to SDG&E, Southern California Edison and EEI also 
complain of an increased administrative burden resulting from 
allocating an energy

[[Page 46197]]

storage asset's cost across multiple plant accounts as proposed in the 
NOPR. Southern California Edison and EEI contend that it would be 
necessary to create multiple unique property records for an energy 
storage asset to allocate its costs across multiple functions. Southern 
California Edison and EEI argue that having multiple records for each 
asset would require significant manual intervention while providing 
little practical value.\164\ Additionally, Southern California Edison 
and EEI assert, without providing any detail, that the NOPR proposal is 
inconsistent with the general principle that each asset should have a 
single record within an accounting system.\165\ Southern California 
Edison and EEI contend that there is neither a precedent for creating 
multiple property records for a single asset, nor a precedent for 
creating a record for a partial asset. Further, EEI argues that to the 
extent the different functions the cost of an energy storage asset 
could be spread across are subject to different depreciation rates, a 
single asset with a unique, individual economic life would be 
depreciated over multiple periods.
---------------------------------------------------------------------------

    \164\ Southern California Edison Comments at 8; and EEI Comments 
at 30.
    \165\ Southern California Edison Comments at 8 and n 8 citing 
Definition No. 8 Paragraph (A)(5), Continuing Plant Inventory 
Record, 18 CFR Part 101 (2012); and EEI Comments at 30.
---------------------------------------------------------------------------

    131. EEI indicates that while it generally opposes the NOPR's 
proposed accounting, it believes that in some circumstances the 
proposal may be a practical alternative for companies desiring to use 
it.\166\ Therefore, EEI advocates that utilities be afforded two 
options to account for energy storage assets that are used to perform 
multiple functions. EEI proposes that utilities be allowed to either: 
(1) Record the costs of multi-function storage asset costs as proposed 
in the NOPR or (2) record the costs of the assets in a single plant 
account based on the primary function of the asset and to allocate 
costs to specific functions performed through the ratemaking process. 
Moreover, EEI recommends that the Form Nos. 1, 1-F, and 3-Q be amended 
to provide for reporting the option each company uses. EEI contends 
that allowing both options will afford companies the ability to 
maintain accounting and reporting records in the most efficient manner 
while providing transparency via reporting and uniformity in the 
ratemaking process.
---------------------------------------------------------------------------

    \166\ EEI Comments at 29-31.
---------------------------------------------------------------------------

    132. Southern California Edison supports EEI's option (2). Southern 
California Edison and EEI contend that the option (2) approach is 
consistent with the approach used for certain assets that provide both 
state-jurisdictional and FERC-jurisdictional functions.\167\ Southern 
California Edison and EEI explain that the ratemaking process may 
include a formula or special study in order to appropriately allocate 
the costs across functions.
---------------------------------------------------------------------------

    \167\ Southern California Edison Comments at 8; and EEI Comments 
at 31-32.
---------------------------------------------------------------------------

Commission Determination
    133. SDG&E's, Southern California Edison's, and EEI's arguments 
that requiring utilities to allocate the costs of energy storage assets 
that perform multiple functions across the relevant energy storage 
plant accounts places an undue administrative burden on utilities are 
unpersuasive. These commenters generally argue that this perceived 
undue administrative burden results from a requirement that utilities 
maintain records that track the usage of energy storage assets and 
costs associated with such use. However, utilities would be required to 
maintain records with this information whether accounting for the costs 
of an asset in multiple accounts as proposed in the NOPR or accounting 
for the costs in a single account as proposed by SDG&E, Southern 
California Edison and EEI. For example, information on the allocation 
of the cost of an energy storage asset to a particular function will 
have to be maintained by utilities operating multi-function, multi-cost 
recovery energy storage assets, regardless of whether the information 
is required to be reported in the reporting forms as proposed in the 
NOPR or if the information is not reported in the forms yet is used in 
ratemaking determinations as proposed by SDG&E, EEI, and Southern 
California Edison. Because utilities with energy storage operations 
that recover any portion of costs on a cost-of-service basis will be 
required to maintain use and cost allocation information on the assets, 
requiring these utilities to implement the NOPR's accounting proposal 
does not result in an additional burden on utilities that could be 
considered unduly burdensome.
    134. Moreover, SDG&E's argument that costs could possibly be 
stranded if a utility does not appropriately account for energy storage 
operations is also unconvincing. This possibility exists throughout the 
utility industry and is not uniquely attributable to utilities with 
energy storage operations. Administrative errors, such as errors in 
accounting, that lead to costs being stranded due to inadequate or 
insufficient internal controls over policies, practices, and procedures 
used to track costs associated with assets represent a risk for all 
utilities whether or not the utilities own energy storage assets. Risks 
of this nature are inherent to all utilities' operations. Utilities 
must maintain adequate, sufficient, and reliable internal controls to 
reduce the probability of this risk affecting operations.
    135. As support for their argument that the NOPR's proposed 
accounting causes an undue administrative burden and that their 
advocated accounting avoids the burden, Southern California Edison and 
EEI contend that their proposal to record the costs of an energy 
storage asset in a single plant account could require utilities to 
implement a formula or special study to appropriately allocate the 
costs of the asset across multiple functions. However, this contention 
does not support their argument. A formula or special study would 
require utilities to maintain the same information on the functions 
performed by an energy storage asset and costs associated with such 
performance, as would be required by the NOPR's proposed accounting. 
Thus, a formula or special study would not avoid the administrative 
burden associated with accounting for energy storage assets and 
operations. Furthermore, Southern California Edison and EEI have not 
provided information to support a determination that the burden would 
be decreased by implementing their proposed accounting. Their proposal 
would result in less transparent reporting of information on energy 
storage operations as compared to the NOPR's proposed accounting.
    136. While the commenters argue that the accounting proposal might 
require increased manual intervention to account for and report storage 
assets, it is not clear that such intervention, if any, results in an 
undue administrative burden. As the Commission observed in the NOPR, 
uniform, transparent, and consistent reporting of information on energy 
storage operations by utilities is essential, especially by those 
seeking to recover costs of energy storage services in cost-based 
rates.\168\ We believe that adopting the NOPR's proposed accounting and 
reporting revisions will improve transparency.\169\ The revisions will 
enhance the Commission's and other form users' ability to make a 
meaningful assessment of a utility's cost-of-service rates, and will 
provide for better monitoring for cross-subsidization. In instances 
where an energy storage asset performs multiple

[[Page 46198]]

functions, it is imperative that costs associated with each function be 
transparent and allocable to the function performed so that cross-
subsidization of costs can be prevented. SDG&E, EEI, and Southern 
California Edison have not provided information that would refute the 
Commission's determination in the NOPR that the accounting proposal is 
not overly burdensome.
---------------------------------------------------------------------------

    \168\ NOPR, FERC Stats. & Regs. ] 32,690 at P 71.
    \169\ Id. P 72.
---------------------------------------------------------------------------

    137. EEI's recommendation that utilities be afforded two options to 
account for and report storage assets that provide multiple services 
and recover associated costs simultaneously under cost-based and 
market-based rate methods is not consistent with the intent of the 
NOPR's proposed accounting and reporting revisions. The NOPR proposed 
one method to account for energy storage assets performing multiple 
functions under multiple cost recovery mechanisms to ensure that 
utilities account for the assets on a uniform and consistent basis. 
EEI's proposal for two methods of accounting could result in similarly-
situated utilities with energy storage assets reporting the same type 
of transaction differently. This would not provide the uniformity 
sought by the accounting and reporting proposals and could disrupt 
consistency, which would make it difficult to compare utilities with 
energy storage operations across the industry. In addition, adopting 
EEI's proposal to record the costs of the assets in a single account 
would reduce the transparency of information reported in the forms. 
This information is critical to the clarity and transparency needed to 
support a reasonable analysis of a utility's cost. Consequently, we 
will not adopt EEI's proposal.
    138. Southern California Edison's assertion that the NOPR 
requirement adopted here is not consistent with Definition No. 8, 
Continuing Plant Inventory Record, is incorrect.\170\ While the 
definition pre-dates the NOPR's accounting and reporting requirements, 
the definition is broad enough such that its premise is as relevant for 
energy storage assets as it is for conventional electric plant assets. 
The accounting and reporting proposals require utilities to maintain a 
detailed record of the descriptive operational and cost information 
associated with energy storage assets consistent with the provisions of 
Definition No. 8.
---------------------------------------------------------------------------

    \170\ 18 CFR Part 101 (2012).
---------------------------------------------------------------------------

    139. Further, Southern California Edison's and EEI's contentions 
that there is no precedent for creating multiple property records for a 
single or partial asset misconstrues the proposed accounting and 
reporting requirements. The accounting and reporting proposals we adopt 
here do not require utilities to maintain multiple records for a single 
or partial asset as Southern California Edison and EEI contend. Rather, 
the reforms maintain the existing requirement of Definition No. 8 that 
utilities maintain descriptive operational and cost information on each 
asset. Moreover, we do not consider allocating the cost of a single 
asset to multiple property accounts to be the same as creating multiple 
property records as though there were multiple assets. A utility can 
maintain information on a single energy storage asset with costs 
allocated to multiple plant accounts in a single record that provides 
descriptive operational and cost information on the asset. 
Additionally, in accordance with General Instruction No. 12, Records 
for Each Plant, utilities are required to maintain a record, by 
electric plant accounts, on the book costs of each plant owned.\171\ 
The requirement to record the cost of a multi-function, multi-cost 
recovery energy storage asset to more than one plant account is 
consistent with this instruction.
---------------------------------------------------------------------------

    \171\ The instructions indicate that the term ``plant'' means 
each generating station and each transmission line or appropriate 
group of transmission lines. This term is also applicable to energy 
storage facilities. 18 CFR Part 101 (2012).
---------------------------------------------------------------------------

    140. EEI argues that if different depreciation rates are applied to 
a single energy storage asset in accordance with each function the 
asset performs the various allocated costs of the asset would be 
depreciated over multiple periods. EEI is correct that there is a 
possibility of this occurring if costs of a single asset were subjected 
to multiple differing depreciation rates. However, this has neither 
been the experience of this Commission nor do we expect that a 
utility's primary rate regulator would subject a single asset to 
multiple depreciation rates. Although the costs of an energy storage 
asset may be allocated across multiple plant accounts, we agree with 
EEI that the asset is a single unique asset with a single economic 
life. Thus, there should be a single depreciation rate applied to the 
asset that allocates in a systematic and rational manner the service 
value of the asset over its service life. To the extent possible, a 
utility should apply a single depreciation rate to an energy storage 
asset.
    141. The reforms adopted here are designed to provide needed 
transparency, but also to reflect a fair balance between the need for 
information and the additional burden on the utility. We believe these 
accounting reforms for energy storage reflect this balance. 
Accordingly, Account 348, Energy Storage Equipment--Production, Account 
351, Energy Storage Equipment--Transmission, and Account 363, Energy 
Storage Equipment--Distribution, as proposed in the NOPR are adopted in 
this Final Rule.
2. Power Purchased Account
Commission Proposal
    142. In the NOPR, the Commission noted that 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, and that some 
companies may be required to purchase power to maintain a desired state 
of charge or pressure. Further, the Commission determined that the 
benefits of enhanced transparency, in this instance, resulting from 
having the cost of power purchased for energy storage operations 
reported separately from other power purchases, outweighs the 
associated burden of requiring the accounting. Therefore, the 
Commission proposed a new Account 555.1, Power Purchased for Storage 
Operations, to report 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; and (4) power purchased to 
initially attain a state of charge, with item 4 being capitalized as a 
component cost of initially constructing the asset.
Comments
    143. Most commenters support the proposed accounting. For example, 
ESA and others state that the new account will enhance the transparency 
of reporting the operations of storage resources.\172\ Hydro 
Association indicates that similar accounting should be established for 
the cost of power purchased for pumped storage operations to account 
for initial unit testing and commissioning.\173\
---------------------------------------------------------------------------

    \172\ ESA Comments at 21-22.
    \173\ Hydro Association Comments at 12-13.
---------------------------------------------------------------------------

    144. Hydro Association states, in particular, for closed-loop 
pumped storage projects, the first unit testing entails pumping or 
charging the upper reservoir. Hydro Association explains that at an 
early stage of development of a pumped storage project, the generating 
station is months away from being declared ``commercial'' and testing 
the station requires energy from the grid to initially attain a fully 
charged state (i.e., a full upper reservoir). Hydro Association argues 
that these initial

[[Page 46199]]

charging costs should be capitalized. Further, Hydro Association 
contends that costs incurred to test the generating station should 
likewise be capitalized into the cost of the project. In contrast to 
Hydro Association's assertion that the existing accounting requirements 
for pumped storage operations are not sufficient, EEI argues that the 
existing requirements appropriately and transparently provide for 
pumped storage plants.\174\
---------------------------------------------------------------------------

    \174\ EEI Comments at 27.
---------------------------------------------------------------------------

Commission Determination
    145. We will adopt the new Account 555.1, Power Purchased for 
Storage Operations, as proposed in the NOPR. The accounting reforms 
here requiring initial charging and testing costs to be capitalized 
seek to apply existing requirements for conventional electric plant, 
such as pumped storage plant, to new energy storage assets. The 
requirements do not seek to differentiate the accounting for new energy 
storage assets from pumped storage plant in this instance.
    146. We disagree with Hydro Association's assertion that the 
existing accounting requirements for pumped storage operations are not 
sufficient. Contrary to Hydro Association's assertion, pumped storage 
is not prohibited, for accounting purposes, by the existing accounting 
rules and regulations from capitalizing costs incurred to initially 
bring a pumped storage facility into operation nor is it prohibited 
from capitalizing costs incurred to test pump storage facilities prior 
to commercial operation. Electric Plant Instruction No. 3, Components 
of Construction Cost, provides that expenses incidental to the 
construction of plant such as cost to initially attain a fully charged 
state to bring the plant into operation may be capitalized as a 
component cost of the plant.\175\ Further, Electric Plant Instruction 
No. 9, Equipment, provides that the costs of plant shall include 
necessary costs of testing or running plant or parts thereof during the 
test period prior to the plant becoming ready for or being placed in 
service.\176\ Consequently, we agree with EEI's statement that the 
existing accounting requirements for pumped storage are sufficient. The 
NOPR proposals for Account 555.1 are adopted in this Final Rule as 
proposed.
---------------------------------------------------------------------------

    \175\ 18 CFR Part 101 (2012).
    \176\ Id.
---------------------------------------------------------------------------

3. Operation and Maintenance Expense Accounts
Commission Proposal
    147. In the NOPR, the Commission observed that there are O&M 
expenses related to the use of 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. Therefore, the Commission proposed new O&M expense accounts 
for energy storage-related O&M expenses that are not specifically 
provided for in the existing O&M expense accounts in the USofA and 
revision of certain existing O&M expense accounts. Specifically, the 
Commission proposed that energy storage expenses 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, to the extent that the existing O&M expense accounts do 
not adequately support recording of the cost.\177\
---------------------------------------------------------------------------

    \177\ NOPR, FERC Stats. & Regs. ] 32,690 at P 96.
---------------------------------------------------------------------------

Comments
    148. The commenters support the proposed O&M expense accounts. Most 
commenters state that the proposed accounts will provide sufficient 
transparency of energy storage-specific O&M expenses.\178\
---------------------------------------------------------------------------

    \178\ See, e.g., ESA Comments at 22; Beacon Power Comments at 
21-22; and California Storage Alliance Comments at 17.
---------------------------------------------------------------------------

Commission Determination
    149. This Final Rule adopts the NOPR proposals for the O&M expense 
accounts with the exception that the account number for Account 582.1 
will be changed to Account 584.1. The name and text of the account will 
remain as proposed in the NOPR.
    150. In addition, the NOPR proposed that the text of Account 592, 
Maintenance of Station Equipment (Major only), and Account 592.1, 
Maintenance of Structures and Equipment (Nonmajor only), be revised 
such that the accounts do not provide for O&M expenses related to 
energy storage operations and also to remove the reference to Account 
363. Accordingly, the following text is struck from Accounts 592 and 
592.1:

``and account 363, Storage Battery Equipment.''
4. New and Amended Form Nos. 1, 1-F, and 3-Q Schedules
Commission Proposal
    151. In the NOPR, the Commission acknowledged that the existing 
schedules in the Form Nos. 1, 1-F, and 3-Q do not provide for reporting 
information on new types of energy storage assets such as batteries and 
flywheels.\179\ Consequently, the Commission proposed to amend several 
schedules of the Form Nos. 1, 1-F, and 3-Q to include energy storage 
plant, purchased power, and O&M expense accounts.\180\ In addition, the 
Commission proposed to add new schedule pages 414-416, Energy Storage 
Operations (Large Plants), and pages 419-420, Energy Storage Operations 
(Small Plants), to the Form Nos. 1 and 1-F to provide for reporting 
operational and statistical information on new types of energy storage 
assets.\181\ The Commission proposed that filers with energy storage 
assets having a rated capacity of 10,000 kilowatts (KW) or more record 
the operations of the assets on schedule pages 414-416, and filers with 
energy storage assets with less than 10,000 KW of capacity record the 
operations on schedule pages 419-420. In addition, the Commission 
sought comment on whether 10,000 KW is an appropriate threshold for 
requiring utilities to report more detailed plant and cost information 
for energy storage plant.\182\ The Commission noted that certain 
existing schedules in the Form No. 1 have a 10,000 KW threshold.\183\ 
However, the Commission opined that this threshold may not be 
appropriate for new energy storage assets that in

[[Page 46200]]

many instances may be rated below 10,000 KW.
---------------------------------------------------------------------------

    \179\ NOPR, FERC Stats. & Regs. ] 32,690 at P 101.
    \180\ NOPR, FERC Stats. & Regs. ] 32,690 at P 106; and Appendix 
B Proposed Amendments to Form Nos. 1, 1-F and 3-Q.
    \181\ The text of the NOPR indicated that the schedules pages 
were 414-417 and 419-421 for the respective Large and Small Plant 
schedules. However, the proposed schedules included in Appendix B of 
the NOPR used different page numbers. We clarify that the schedule 
page numbers are 414-416 and 419-420, for the respective Large and 
Small Plant schedules, as indicated in this Final Rule.
    \182\ NOPR, FERC Stats. & Regs. ] 32,690 at P 103.
    \183\ See Form No. 1, schedule pages 408-409, Generating Plant 
Statistics (Large Plants) and schedule pages 410-411, Generating 
Plant Statistics (Small Plants). Schedule pages 408-409 require 
filers to report more detailed information for generating assets 
with a rated capacity of 10,000 KW or more than schedule pages 410-
411, which require less detailed information for generating assets 
with a rated capacity of less than 10,000 KW.
---------------------------------------------------------------------------

Comments
    152. Most commenters support the NOPR's forms proposals, and a few 
commenters recommend revisions to the forms in addition to those 
proposed.\184\ Consistent with its recommendation that the Commission 
implement two options to account for energy storage assets, EEI 
proposes that the forms provide for disclosing the specific option a 
utility is using to account for the assets.\185\ However, because we 
are not adopting EEI's recommendation for two accounting options, its 
disclosure proposal is unnecessary as utilities will have one uniform 
method for accounting for energy storage assets.
---------------------------------------------------------------------------

    \184\ See, e.g., APPA Comments at 5; Beacon Comments at 22-23; 
California Storage Alliance Comments at 19; and ESA Comments at 23.
    \185\ EEI Comments at 5.
---------------------------------------------------------------------------

    153. Hydro Association contends that there are shortcomings in the 
way the Form No. 1 treats existing pumped storage plants, as they are 
now used, and it suggests modifications that it believes will improve 
reporting of information on the assets. Hydro Association recommends 
that the heading of Line 6 ``Plant Hours Connect to Load While 
Generating'' of schedule pages 408-409, Pumped Storage Generating Plant 
Statistics (Large Plants), in the Form No. 1 be changed to read ``Plant 
Hours Connect to Load.'' \186\ Hydro Association reasons that the total 
hours a facility is synchronized and connected to the grid are 
important to identify. Hydro Association explains that a facility's 
effectiveness is based on its total utilization factor, which Hydro 
Association describes as the sum of hours generating, pumping, and 
condensing. Hydro Association asserts that this sum should be reported 
on Line 6 under its proposed heading. Alternatively, Hydro Association 
proffers that if further detail is needed, the heading of Line 6 can 
remain as is and two new line items can be added to the schedule to 
report pumping and condensing hours.
---------------------------------------------------------------------------

    \186\ Hydro Association Comments at 11.
---------------------------------------------------------------------------

    154. Further, Hydro Association also contends that Line 38, 
``Expenses for KWh (line 37/9)'' incorrectly calculates the cost per 
kilowatt hour (KWh) of pumped storage operations.\187\ Hydro 
Association asserts that the calculation should include energy 
generated and energy used for pumping operations. Hydro Association 
proposes that Line 38 be revised to read as ``Expenses for KWh (line 
37/9+10).''
---------------------------------------------------------------------------

    \187\ Id.
---------------------------------------------------------------------------

    155. TAPS recommends revisions to new schedule pages 414-416, 
Energy Storage Operations (Large Plants).\188\ TAPS observes that the 
instruction for column heading (l) refers to ``revenues from energy 
storage operations'' while the name of the column is ``Revenues from 
the Sale of Stored Energy.'' TAPS asserts that because revenues from 
energy storage operations can be garnered by means other than from 
energy sales, the name of the column should be revised to be consistent 
with the instructions of the column or additional columns should be 
created, with corresponding instructions, to report other types of 
revenues.
---------------------------------------------------------------------------

    \188\ TAPS Comments at 28-29.
---------------------------------------------------------------------------

    156. In regard to the 10,000 KW threshold, California Storage 
Alliance states that it believes 10,000 KW is an appropriate threshold 
for requiring a difference in the reporting requirements for the 
assets.\189\ In contrast, Beacon and ESA recommend a higher threshold 
of 20,000 KW.\190\ Beacon and ESA assert that this threshold would 
align with the Small Generator Interconnection threshold and the 
capacity value for many existing and planned energy storage assets.
---------------------------------------------------------------------------

    \189\ California Storage Alliance Comments at 19.
    \190\ Beacon Comments at 22; and ESA Comments at 22-23.
---------------------------------------------------------------------------

Commission Determination
    157. We generally agree with the premise of Hydro Association's 
contention that Line 6 of schedule pages 408-409 could benefit from 
additional detail. However, the cost of additional detail must be 
weighed against any associated benefit that could result. To this end, 
we strive to achieve a balance such that the cost of implementing new 
reporting requirements does not excessively exceed the benefits of 
implementation. A particularly important benefit to the Commission of 
additional detail is that it provides data necessary for the regulation 
and review of companies' operations. Hydro Association has neither 
explained how information on pumping and condensing hours is needed for 
the regulation and review of pumped storage operations nor has it 
explained how the information would be beneficial for other uses. Hydro 
Association indicates that this information will provide for a measure 
of a facility's effectiveness, however, it is not clear that the cost 
of requiring this information is on par with any perceived benefits or 
that the requirement would not be overly burdensome. Consequently, we 
will not adopt Hydro Association's proposal to include the sum of 
generating, condensing and pumping on Line 6, nor will we adopt its 
alternate proposal to add two new line items to the schedule.
    158. With regard to Hydro Association's contention that Line 38 of 
schedule pages 408-409 incorrectly calculates the cost per KWh of 
pumped storage operations, this line is not intended to report this 
cost, rather it is intended to report the cost per KWh of energy 
generated and transmitted to the grid. Line 38 of the schedule includes 
a formula that requires filers to divide total production expenses 
reported on Line 37 by energy generated and transmitted to the grid 
reported on Line 9. Nevertheless, we recognize Hydro Association's 
underlying concern that, as a conforming change given the other 
accounting requirements in this Final Rule, the schedule should report 
this information, including the energy generated and energy used in 
pumping, as illustrated in the formula example submitted by Hydro 
Association--Line 37/9+10.
    159. We agree that reporting this information on schedule pages 
408-409 will help create a more accurate database for benchmarking and 
O&M cost studies, and this information also will assist interested 
parties', including the Commission's, review of the operations of 
pumped storage facilities across the industry. We note that the data 
inputs needed to perform the calculation are currently required to be 
reported on Lines 9, 10 and 37 of schedule pages 408-409, so this 
requirement is not wholly new and the burden on utilities to calculate 
and report the information specifically on schedule pages 408-409 is 
minimal. Accordingly, the item on Line 38 of schedule pages 408-409 is 
revised to read ``Expenses per KWh of Generation (line 37/line 9)'' and 
a new Line 39 is added which reads ``Expenses per KWh of Generation and 
Pumping (line 37/(line 9 + line 10)).''
    160. TAPS asserts that revenues from energy storage operations can 
originate from activities other than energy sales, thus it recommends 
that proposed schedule pages 414-416 be revised to provide for other 
types of revenues. We agree that there are potentially other activities 
that energy storage operators can engage in to generate revenue. For 
example, as TAPS noted, an energy storage operator can conceivably earn 
revenues from the sale of storage capacity. While we are not aware of 
any instances where these types of storage capacity transactions have 
occurred, to ensure that the schedule provides

[[Page 46201]]

adequate flexibility to allow for the reporting of all revenues from 
energy storage operations we will revise the name of the column to read 
``Revenues from Energy Storage Operations.'' We will not create 
additional columns to report the various types of revenue because the 
instructions to the schedule already require filers to disclose this 
information in a footnote.
    161. Beacon and ESA recommend that the Commission align the 
threshold for detailed reporting in the new schedules with the existing 
20,000 KW threshold established in Order No. 2006 for the 
interconnection of small generators.\191\ To this end, Beacon and ESA 
propose a 20,000 KW threshold as opposed to the 10,000 KW proposed in 
the NOPR. However, the 20,000 KW threshold in Order No. 2006 was 
established notwithstanding the requirement that small generators 
having 10,000 KW or more but less than 20,000 KW that are subjected to 
the Commission's accounting and reporting requirements would be 
subjected to a higher reporting burden than companies with generators 
of less than 10,000 KW. In this instance, the Commission determined 
that while there is a need to further remove barriers to participation 
in energy markets by establishing terms and conditions under which 
public utilities must provide interconnection service, there is also a 
parallel need for detailed information on the activities and operations 
of companies using these assets in the provisioning of utility 
services. Thus, the Commission maintained its existing 10,000 KW 
threshold for these small generators.
---------------------------------------------------------------------------

    \191\ Standardization of Small Generator Interconnection 
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ] 
31,180, order on reh 'g, Order No. 2006-A, FERC Stats. & Regs. ] 
31,196 (2005), order on clarification, Order No. 2006-B, FERC Stats. 
& Regs. ] 31,221 (2006). This order originally set forth the terms 
and conditions under which public utilities must provide 
interconnection service to Small Generating Facilities of no more 
than 20,000 KW.
---------------------------------------------------------------------------

    162. Beacon and ESA have not provided information that supports a 
decreased reporting burden for energy storage assets over 10,000 KW as 
compared to the reporting burden of conventional assets that are 
currently subject to the 10,000 KW threshold. Nor has Beacon or ESA 
provided information that would support increasing the existing 10,000 
KW threshold for conventional assets to maintain parity between those 
assets and energy storage assets. Their proposal may result in an 
unduly discriminatory reporting requirement for energy storage assets 
compared to conventional assets, therefore we will not adopt the 
recommended 20,000 KW reporting threshold.
    163. We will adopt the NOPR's proposed 10,000 KW threshold as this 
amount is neither unduly conservative nor is it overly burdensome. As 
we indicated in the NOPR, information that would be reported for energy 
storage assets and operations differs little from other data public 
utilities maintain under the USofA.\192\ 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.
---------------------------------------------------------------------------

    \192\ NOPR, FERC Stats. & Regs. ] 32,690 at P 73.
---------------------------------------------------------------------------

    164. Finally, we will amend schedule pages 2-4, 204-207, 320-323, 
324a-324b, 326-327, 397, and 401a of the Form Nos. 1, 1-F, and 3-Q as 
proposed in the NOPR.\193\ We note that these amendments include 
revising schedule page 401a, Electric Energy Account, of the Form No. 1 
to change the title of line item 10 to ``Purchases (other than for 
Energy Storage)'' and add a new line item 11 ``Purchases for Energy 
Storage'' to provide for reporting power purchased for energy storage 
operations. These changes require an additional line item on Form No. 1 
schedule page 401a to provide for reporting stored energy because total 
net sources of energy must equal total disposition of energy as 
instructed by the requirement on Line 30 of the schedule. Utilities 
with energy storage operations that have stored energy as of the 
reporting date of the form must report the amount by megawatt hour in 
the schedule so that total net sources of energy is equal to total 
disposition of energy reported. Accordingly, as a conforming change, a 
new line item titled ``Total Energy Stored'' will be added to schedule 
page 401a under the heading ``Disposition of Energy.''
---------------------------------------------------------------------------

    \193\ NOPR, FERC Stats. & Regs. ] 32,690 at Appendix B Proposed 
Amendments to Form Nos. 1, 1-F, and 3-Q.
---------------------------------------------------------------------------

5. Other Accounting and Reporting Issues
a. Existing Waivers of Accounting and Reporting Requirements
Commission Proposal
    165. In the NOPR, the Commission proposed 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 and that seek recovery of a 
portion of service costs under cost-based rates, be required to forego 
the previously issued waivers and account for and report all cost and 
operational information to the Commission in accordance with its 
accounting and reporting requirements.\194\ In addition, the Commission 
also inquired whether there should be a percentage of cost recovery 
threshold 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.
---------------------------------------------------------------------------

    \194\ Id. P 75.
---------------------------------------------------------------------------

Comments
    166. Most commenters agree with the proposal to rescind previously 
issued waivers and many of these commenters argue that there should not 
be a percentage threshold that triggers the requirement. California 
Storage Alliance states that rescinding the waivers will enhance 
transparency and facilitate development and monitoring of the cost-
based portion of rates.\195\ Further, California Storage Alliance 
states that there should not be a percentage threshold that triggers 
accounting and reporting requirements. California Storage Alliance, and 
others,\196\ also recommend that in instances where a competitive 
solicitation process is used to determine recovery of the cost-based 
portion of rates, a public utility should not be required to forego any 
reporting and accounting waivers. In further describing their position, 
these commenters suggest that a particular ``storage asset may be 
capable of simultaneously providing two distinct functions, one 
traditionally cost-based use, and another generally market-based.'' 
They then posit the possibility of a public utility issuing a 
competitive solicitation solely for the ``cost-based use.'' Their 
comments then assert that the winning bidder would be obligated to 
provide the ``cost-based service'' and would be paid through a ``rate-
based mechanism.'' \197\ We also received requests to clarify that the 
waivers will only be rescinded if energy storage is involved.\198\
---------------------------------------------------------------------------

    \195\ California Storage Alliance Comments at 10.
    \196\ California Storage Alliance Comments at 10-11; ESA 
Comments at 18; and Beacon Comments at 18.
    \197\ Id.
    \198\ Indicated Suppliers Comments at 6-11; EPSA Comments at 13; 
and EEI Comments at 33-34.
---------------------------------------------------------------------------

Commission Determination
    167. We will adopt the NOPR proposal requiring public utilities to 
forego previously issued accounting and reporting waivers in instances 
where the utility seeks to recover costs associated with operation of 
an energy storage asset simultaneously under market-based and

[[Page 46202]]

cost-based rate recovery mechanisms. We will not impose a percentage 
recovery threshold, therefore any cost-based recovery of the cost will 
trigger rescission of previously granted accounting and reporting 
waivers.
    168. Regarding the comments of California Storage Alliance, ESA, 
and Beacon, the Commission clarifies that sellers under a competitive 
solicitation that meets the requirements of this Final Rule \199\ will 
not be required to forego any prior accounting and reporting waivers. 
However, we feel it necessary to explain that the reason for this 
outcome differs from what these commenters seem to propose.
---------------------------------------------------------------------------

    \199\ See supra PP 87-90.
---------------------------------------------------------------------------

    169. Their comments seem to indicate a belief that there are some 
products that are inherently cost-based and others that are inherently 
market-based, and that if a competitive solicitation were held for a 
cost-based product, the resulting rates would still be cost-based. We 
are not persuaded by these commenters' arguments that products should 
be classified as inherently cost-based or market-based. Some potential 
sellers of these products will qualify to sell them at market-based 
rates because they either lack market power in the relevant product 
market, or it has been adequately mitigated. Other sellers who do not 
qualify to make market-based sales, because they either have market 
power or cannot prove they lack it, will be limited to charging cost-
based rates.
    170. Under the competitive solicitation proposal at bar, proof that 
the competitive solicitation meets the requirements of this Final Rule 
will demonstrate that a seller qualifies to make market-based sales at 
the rates resulting from the solicitation, and thus can avoid having to 
justify those rates on a cost-of-service basis. Because such sellers 
will still only be making market-based sales, there is no reason to 
rescind the prior accounting and reporting waivers that were granted 
because they would only be making market-based rate sales. Cost-based 
sales of ancillary services have always been an option for third party 
sellers, and remain an option for them after issuance of this Final 
Rule. However, all of the requirements of cost-of-service regulation, 
such as the very accounting and reporting requirements at issue here, 
would apply to such sales. We also clarify that the requirement for a 
company to forego previously issued accounting and reporting waivers, 
in this instance, is only applicable when energy storage is involved. 
There may be other occasions when previously issued waivers may be 
rescinded however those occasions are outside the scope of this 
rulemaking.
b. Definition of Energy Storage Asset or Technology
    171. EEI asks that the Commission clarify the definition of energy 
storage assets or technologies that are subject to these accounting and 
reporting requirements.\200\ EEI proposes that the Commission define 
energy storage assets as ``commercially available technology that is 
capable of absorbing energy, storing energy, and subsequently releasing 
the energy to the electric system.'' \201\ Further, EEI states that 
certain other energy storage assets should be exempted from the Final 
Rule, and thus the new accounts, if the function of the asset is so 
clearly related to activities properly reflected in existing accounts 
such that the asset is not designed to be used as an ``energy storage 
asset'' under the definition articulated in this Final Rule. EEI 
states, for example, that the following assets or technologies should 
be exempted:
---------------------------------------------------------------------------

    \200\ EEI Comments at 26-28.
    \201\ Id.

Batteries used primarily in connection with the control and 
switching of electric energy produced and the protection of electric 
circuits and equipment that are recorded in the following existing 
---------------------------------------------------------------------------
FERC accounts:

Account 315, Accessory Electric Equipment
Account 324, Accessory Electric Equipment (Major Only)
Account 345, Accessory Electric Equipment

Batteries used in connection with controlling station equipment or 
for general station purposes that are recorded in the following 
existing FERC accounts:

Account 353, Station Equipment

Batteries used in connection with controlling station equipment or 
for general station purposes that are recorded in the following 
existing FERC accounts:

Account 362, Station Equipment

Compressed air systems used for pneumatic or air tools that are 
recorded in the following existing FERC accounts:

Account 316, Miscellaneous Power Plant Equipment
Account 325, Miscellaneous Power Plant Equipment (Major Only)
    Account 346, Miscellaneous Power Plant Equipment
Commission Determination
    172. We agree with EEI that there are certain assets that are 
excluded from the scope of this Final Rule, however, we will not adopt 
EEI's proposed definition for an energy storage asset or technology. 
The definition is too broad and could be interpreted to include 
storage-type technologies that are outside the scope of this Final 
Rule. As EEI indicated, the assets listed above are the type of assets 
that should be excluded. This list is not exhaustive; rather it is an 
example of the type of assets and activities served by those assets 
that are a baseline indicator of assets that are outside the scope of 
the accounting and reporting requirements adopted in this Final Rule. 
For the purposes of this Final Rule, an energy storage asset shall be 
defined as property that is interconnected to the electrical grid and 
is designed to receive electrical energy, to store such electrical 
energy as another energy form,\202\ and to convert such energy back to 
electricity and deliver such electricity for sale, or to use such 
energy to provide reliability or economic benefits to the grid. The 
term may include hydroelectric pumped storage and compressed air energy 
storage, regenerative fuel cells, batteries, superconducting magnetic 
energy storage, flywheels, thermal energy storage systems, and hydrogen 
storage, or combination thereof, or any other technologies as the 
Commission may determine.\203\
---------------------------------------------------------------------------

    \202\ Electrical energy may be converted to and stored as 
several different forms of energy such as chemical, mechanical, and 
thermal energies.
    \203\ Although hydroelectric pumped storage is an energy storage 
technology in accordance with our definition, the accounting and 
reporting requirements of this rulemaking do not apply to the 
assets, notwithstanding the revisions to schedule pages 408-409. As 
we indicated previously, our existing accounting and reporting 
requirements for pumped storage sufficiently accommodate pumped 
storage assets and operations.
---------------------------------------------------------------------------

c. Incorporating Energy Storage Plant Accounts Into Existing Formula 
Rates
    173. EEI requests that the Commission pre-authorize inclusion of 
the new energy storage plant and O&M expense accounts in existing 
formula rates without the need for separate, company-specific section 
205 proceedings.\204\ EEI contends that many jurisdictional utilities 
that own and operate energy storage technologies account for the assets 
in existing accounts that are incorporated in formula rates. EEI states 
that to the extent the new accounts require a revision to existing 
filed rates, the Commission should allow such changes to be filed in a 
compliance filing in this proceeding.
---------------------------------------------------------------------------

    \204\ EEI Comments at 32-33.
---------------------------------------------------------------------------

Commission Determination
    174. We agree with EEI that utilities currently owning and 
operating these assets are using existing accounts and reporting 
schedules. Moreover, in many instances these accounts are incorporated 
in the companies' formula rate templates and costs reported in the 
accounts are through operation of the formula rate included in rate

[[Page 46203]]

determinations. For some of these companies, transferring amounts from 
an existing plant account under a particular functional classification 
to a new energy storage plant account under the same functional 
classification may involve a relatively straight-forward transfer of 
cost. In this type of situation, a compliance filing will provide 
adequate transparency to allow interested parties, including the 
Commission, to review amounts being transferred from one account to 
another and also to establish the incorporation of the new energy 
storage plant and O&M expense accounts in the formula rate tariff. 
However, a compliance filing may not be suitable for all situations.
    175. For example, in instances where a company intends on recording 
the costs of an energy storage asset to multiple plant accounts in 
accordance with a plan to support multiple functions using the asset, a 
compliance filing may not provide for an adequate review of the many 
variables involved that can impact the determination of the appropriate 
allocation of the cost and rates charged based on the allocation. 
Moreover, if a company intends on recovering capital and O&M costs of 
the asset simultaneously under cost-based and market-based rate 
recovery mechanisms, a compliance filing would not provide sufficient 
notice or review of the cost to be recovered under the two rate 
mechanisms. Consequently, because a compliance filing is not 
appropriate for all situations, we will limit approval of its use to 
companies that are transferring amounts from an existing plant account 
under a particular functional classification to a new energy storage 
plant account under the same functional classification. Transfers of 
the costs to other plant accounts after this initial compliance filing 
shall be subject to the requirements of Electric Plant Instruction 
No.12, Transfers of Property,\205\ as proposed in the NOPR,\206\ and 
the provisions of utilities' formula rate tariffs, as applicable. 
Utilities that do not qualify to use the compliance filing process must 
first receive approval from a relevant rate regulator to revise their 
existing formula rate tariffs to incorporate the new energy storage 
accounts.
---------------------------------------------------------------------------

    \205\ 18 CFR Part 101 (2012).
    \206\ NOPR, FERC Stats. & Regs. ] 32,690 at P 82.
---------------------------------------------------------------------------

d. Depreciation Rates for Energy Storage Assets
Commission Proposal
    176. In the NOPR, the Commission proposed that the cost of energy 
storage assets be charged to depreciation expense using the 
depreciation rates developed for each function.\207\
---------------------------------------------------------------------------

    \207\ Id.
---------------------------------------------------------------------------

Comments
    177. Commenters generally support this proposal. For example, 
Beacon and ESA acknowledge support for the proposal.\208\ EEI 
recommends that instead of requiring depreciation rates to be based on 
a utility's existing rate for a particular function, the Commission 
allow utilities to set initial depreciation rates for new energy 
storage battery equipment based on the manufacturer's estimated useful 
life, prior to the utilities receiving approval of new depreciation 
rates through a rate proceeding where new approved rates are ordered 
for these accounts.\209\ EEI explains that the current life of storage 
batteries is expected to be approximately 10 to 15 years and it 
contends that this expected life can be substantially less than the 
life used to calculate the depreciation rate for the function the asset 
may be classified under.
---------------------------------------------------------------------------

    \208\ Beacon Comments at 19; and ESA Comments at 19.
    \209\ EEI Comments at 32.
---------------------------------------------------------------------------

Commission Determination
    178. For accounting purposes, utilities are required to use 
percentage rates of depreciation that are based on a method of 
depreciation that allocates in a systematic and rational manner the 
service value of depreciable property over the service life of the 
property.\210\ Where composite depreciation rates are used, the rate 
should be based on the weighted average estimated useful lives of 
depreciable property comprising the composite group. Furthermore, 
estimated service lives of depreciable property must be supported by 
engineering, economic, or other depreciation studies.\211\ To the 
extent that an energy storage asset, such as a battery, has an 
estimated useful service life that is supported by engineering, 
economic, or other studies of the manufacturer or utility, the 
depreciation rate derived from such study must result in a systematic 
and rational allocation of the asset's costs over the estimated service 
life. Therefore, for accounting purposes, utilities may set initial 
rates for new energy storage assets based on manufacturer or utility 
estimated service lives that are supported by engineering, economic or 
other studies. In addition, as we indicated above, utilities should use 
a single depreciation rate for an energy storage asset regardless the 
number of functions to which the costs of the asset are allocated.\212\
---------------------------------------------------------------------------

    \210\ General Instruction No. 22, Depreciation Accounting, 18 
CFR Part 101 (2012).
    \211\ Id.
    \212\ See supra P 128.
---------------------------------------------------------------------------

e. Jurisdictional Authority
    179. The California PUC warns that the Commission's authority over 
the accounting and reporting for energy storage assets should not limit 
or infringe upon States' jurisdictional authority over the assets as 
the majority of the assets are likely to be financed pursuant to state 
jurisdictional procurement authority.\213\
---------------------------------------------------------------------------

    \213\ California PUC Comments at 8.
---------------------------------------------------------------------------

Commission Determination
    180. The accounting and reporting requirements of this rulemaking 
are not intended to limit or infringe upon States' jurisdictional 
authority. Pursuant to section 301(a) of the Federal Power Act (FPA), 
the Commission has authority to prescribe a system of accounts and 
rules and regulations that are applicable in principle to all licensees 
and public utilities subject to the Commission's accounting and 
reporting requirements.\214\ The Commission may determine the accounts 
in which particular outlays and receipts will be entered, charged or 
credited. The amendments to the accounting and reporting requirements 
are in accordance with the authority bestowed upon the Commission under 
the FPA and as such do not preempt or affect any jurisdiction a State 
commission or other State authority may have under applicable State and 
Federal law or limit the authority of a State commission in accordance 
with State and Federal law.
---------------------------------------------------------------------------

    \214\ 16 U.S.C. 825(a).
---------------------------------------------------------------------------

f. Implementation Date
    181. EEI requests clarification of the implementation date of the 
proposed accounting and reporting requirements. EEI states that it 
believes assets and related amounts recorded in other accounts under 
the existing accounting requirements should be reclassified to the new 
energy storage accounts provided the asset meets the definition of an 
energy storage asset.\215\ However, EEI argues that it would not be 
beneficial or cost effective to require utilities to retroactively 
amend prior year reports to implement the requirements. Therefore, EEI 
recommends that the accounting and reporting requirements be effective 
prospectively only.
---------------------------------------------------------------------------

    \215\ EEI Comments at 28-29.

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

[[Page 46204]]

Commission Determination
    182. While we agree with EEI that it may not be cost effective to 
require utilities with energy storage assets to retroactively amend 
prior year reports to implement the accounting and reporting 
requirements of this Final Rule; we disagree with EEI's contention that 
it would not be beneficial to interested parties desiring more 
transparent reporting of the costs associated with energy storage 
operations. In these instances, the Commission must weigh the perceived 
cost of implementing a requirement against the expected benefits of 
implementation. Although requiring utilities with energy storage assets 
to retroactively implement the requirements would provide a more 
transparent historical record of these utilities energy storage 
operations, this information would not be necessary to provide 
oversight of these utilities energy storage operations going forward. 
Moreover, it is not clear that the benefits of retroactive 
implementation are sufficient to justify the cost. Consequently, we 
will not require utilities to retroactively implement the accounting 
and reporting requirements.
    183. Utilities subject to the Commission's accounting and reporting 
requirements must implement the requirements as of January 1, 2013. 
Utilities are not required to adjust prior year, comparative 
information reported in 2013 Form Nos. 1 and 1-F that must be filed by 
April 18, 2014, nor are they required to adjust prior year, comparative 
information reported in 2013 Form No. 3-Q reports. However, a footnote 
disclosure must be provided describing any amounts transferred from an 
existing account to a new energy storage account.
    184. Due to outdated software, discussed in more detail below, the 
adopted new and revised schedules of Form Nos. 1, 1-F and 3-Q will not 
be available for use as of the effective date of this Final Rule. 
Consequently, utilities with energy storage assets and those that 
acquire the assets at a later date must continue or begin, as 
appropriate, using the existing form schedules to report energy storage 
assets pending availability of the new and revised schedules. 
Furthermore, we direct the Chief Accountant to issue interim accounting 
and reporting guidance for utilities to report to the Commission the 
costs of energy storage operations contemplated in this Final Rule 
until the new and revised schedules are available.
    185. Regarding the reporting software issues, the Commission's 
forms software applications are built with Visual FoxPro development 
tools and must be installed on a Windows-based computer. Microsoft, the 
Visual FoxPro vendor, announced in 2007 that it would no longer sell or 
issue new versions of Visual FoxPro and would provide support for it 
only through 2015. Also, over time, the Commission has found that it is 
difficult to update tables in the software to accommodate revisions to 
existing schedules and add new schedules to the forms because Visual 
FoxPro does not allow data tables to exceed two gigabytes. These data 
size limitations will soon restrict the Commission's ability to add 
data fields in the forms. These limitations make the forms software 
application outmoded, ineffective, and unsustainable.
    186. Pursuant to Sections 141.1, 141.400, and 385.2011 of the 
Commission's Regulations,\216\ Form Nos. 1 and 3-Q must be submitted 
using electronic media.\217\ Due to technology changes that will render 
the current forms filing process outmoded, ineffective, and 
unsustainable, the Commission will discontinue the use of Commission-
distributed software to file forms. Moreover, because of the software 
limitations, the new and revised form schedules will not be available 
to utilities with energy storage assets and those that acquire the 
assets later as of the effective date of this Final Rule. Consequently, 
due to the time lag between implementation of the accounting and 
reporting requirements adopted here and the availability of a filing 
platform that accommodates the Commission's reporting forms, utilities 
should submit their 2013 Form No. 1 and 2014 Form No. 3-Qs using the 
existing forms filing process until an updated filing platform is made 
available by the Commission. Commission staff will issue appropriate 
notices and hold technical conferences if necessary concerning changes 
to the filing process.\218\
---------------------------------------------------------------------------

    \216\ 18 CFR 141.1, 141.400, and 385.2011 (2012), respectively.
    \217\ Form No. 1-F filers may also submit the reports 
electronically; however, the Commission's regulations do not 
explicitly require these filers to submit the reports 
electronically. See 18 CFR 141.2 (2012).
    \218\ Filers with energy storage assets and operations may be 
required to amend and refile their 2013 Form Nos. 1 and 1-F and 2014 
Form No. 3-Q to report energy storage operation information in the 
schedules adopted in this final rule as a result of the anticipated 
new filing platform. However, these filers will not be required to 
amend and refile previously submitted 2013 Form No. 3-Qs.
---------------------------------------------------------------------------

D. Other Issues

    187. Some commenters raised issues beyond the scope of the NOPR. 
WSPP argues that public utility participation in a competitive market 
for ancillary services is hindered by certain OATT requirements 
applicable to network transmission customers. Specifically, WSPP refers 
to the requirement that network resources be undesignated as such, and 
thus lose their firm network transmission service, when they are 
committed to third-party sales instead of network load obligations. 
WSPP points to timing mismatches between the operational needs of 
ancillary service use and the undesignation requirements of the OATT as 
the main source of this issue. It argues that the Commission previously 
acknowledged these issues in connection with contingency reserves under 
the Southwest Reserve Sharing Group.\219\ WSPP argues that this 
undesignation requirement hinders robust participation from network 
transmission customers, including the transmission providers 
themselves, in ancillary service markets.
---------------------------------------------------------------------------

    \219\ WSPP Comments at 19-21.
---------------------------------------------------------------------------

    188. EEI makes similar arguments with respect to the network 
resource undesignation requirements, and asks that the Commission 
remain receptive to utility-specific requests for flexibility.\220\
---------------------------------------------------------------------------

    \220\ EEI Comments 21-22.
---------------------------------------------------------------------------

    189. Hydro Association and Public Interest Organizations argue that 
the Commission should develop policies that facilitate long-term 
contracts with energy storage owners. Hydro Association asserts that 
the Commission should solicit further input on policies that would 
allow RTO, ISO, and stand-alone transmission providers to enter into 
long-term contracts with energy storage owners.\221\ Public Interest 
Organizations make similar arguments.\222\
---------------------------------------------------------------------------

    \221\ Hydro Association Comments at 4-6.
    \222\ Public Interest Organizations Comments at 11.
---------------------------------------------------------------------------

    190. Shell Energy suggests that the current distinction between 
Energy Imbalance and Generator Imbalance is unnecessary, and that the 
two services should be combined into a single product. Shell Energy 
cites similar definitions in the EQR Data Dictionary, and states that 
treating the two services as different products provides little 
benefit, creates unnecessary complexity and may result in confusion and 
regulatory uncertainty.\223\
---------------------------------------------------------------------------

    \223\ Shell Energy Comments at 3-4.
---------------------------------------------------------------------------

    191. Shell Energy also urges the Commission to recognize 
``Balancing Reserves'' as a separate energy and capacity product used 
to firm variable energy resources. Shell Energy argues that such a 
product would be differentiated from ancillary services because, unlike 
ancillary services, it would not be limited to addressing

[[Page 46205]]

contingencies. Shell Energy seeks clarification that such a product 
would not be considered an ancillary service, and thus would not be 
subject to the Avista restrictions. Rather it would be subject to a 
seller's existing authorization to sell energy and capacity at market-
based rates.\224\ EPSA makes similar arguments regarding the need for a 
new, non-contingency-related balancing reserves product.\225\ While 
WSPP's comments do not specifically seek to identify a new product 
based on whether or not it can be used for issues other than 
contingencies, as do Shell Energy and EPSA, WSPP nevertheless makes 
certain similar arguments in part of its comments. WSPP asserts that 
sellers may not always wish to sell specific ancillary services, but 
rather may wish to sell ``flexible capacity'' products capable 
generally of fulfilling multiple OATT schedules. While its comments are 
not entirely clear on this point, WSPP could be interpreted to argue 
that the Commission should recognize flexible capacity as a product 
different from ancillary services.\226\
---------------------------------------------------------------------------

    \224\ Shell Energy Comments at 5-6.
    \225\ EPSA Comments at 10-11.
    \226\ WSPP Comments at 7.
---------------------------------------------------------------------------

    192. AWEA requests that the Commission explore the role that 
dynamic transfer capability, or lack thereof, plays in protecting 
against exertion of market power. AWEA argues that lack of dynamic 
transfer capability severely constrains competitive ancillary service 
markets in many parts of the country. AWEA suggests that the Commission 
could require transmission providers to analyze, inventory, and market 
dynamic scheduling capability on a non-discriminatory basis.\227\
---------------------------------------------------------------------------

    \227\ AWEA Comments at 3.
---------------------------------------------------------------------------

    193. Powerex argues that there may be certain locations where there 
is sufficient market liquidity such that a seller should be able to 
make ancillary service sales without performing a separate market power 
analysis. Powerex believes that these locations might be defined by 
some measure of market liquidity, or by a specific minimum number of 
potential sellers, and gives as examples the trading hubs of Mid-
Columbia, California-Oregon Border, Palo Verde, Four Corners, and Mead. 
Powerex does not suggest specific liquidity metrics, but does have 
suggestions regarding the appropriate minimum number of potential 
suppliers. It suggests that third-party sales to a transmission 
provider could be deemed competitive any time there are: (1) At least 
three potential suppliers, each capable of providing 100 percent of the 
buyer's needs for the ancillary service in question; or (2) at least 
five potential suppliers, each capable of meeting a significant portion 
(e.g., at least 25 percent) of the buyer's need for the ancillary 
service in question.
Commission Determination
    194. With respect to WSPP's request for more flexibility on the 
requirements for network resource undesignation, the Commission 
declines to consider such changes on a generic basis at this time. This 
undesignation requirement is intended to ensure that network 
transmission customers cannot inappropriately withhold firm 
transmission capacity from potential competitors. While WSPP is correct 
that the Commission has permitted limited deviations from this 
requirement in connection with established reserve sharing groups, we 
are not persuaded that a more general relaxation is justified. WSPP 
indicates in its comments that a public utility is unable to 
undesignate the network resource providing the energy associated with 
the provision of ancillary services because the unit providing the 
energy may differ from the unit providing the capacity. This suggests 
that the public utility will be using transmission service from a unit 
that is different from the unit for which transmission service has been 
reserved. Thus, WSPP is essentially asking the Commission to permit a 
public utility transmission provider to implicitly use firm point-to-
point transmission service without reserving it or paying for it. The 
Commission has previously expressly prohibited this practice and 
nothing in the comments suggests that the Commission's concerns are no 
longer valid.\228\ Further, participating in a reserve sharing group 
differs from making third-party market sales of ancillary services. A 
reserve sharing group essentially expands a public utility transmission 
provider's native load obligations to serving other load serving 
entities' native load in the event of a contingency with like 
protection in return. Permitting a public utility transmission provider 
to deliver energy associated with its reserve sharing group obligations 
without undesignating the resource providing the energy is an 
appropriate recognition of the network service elements of reserve 
sharing arrangements. On the other hand, market sales of ancillary 
services must be delivered using point-to-point transmission service.
---------------------------------------------------------------------------

    \228\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 834.
---------------------------------------------------------------------------

    195. With respect to the requests of Hydro Association and Public 
Interest Organizations to facilitate long-term contracting with energy 
storage owners, we see no basis for any additional action at this time. 
In bilateral markets, assuming that parties are able to avoid the 
Avista restrictions through use of one of the options provided in this 
rule, potential buyers including transmission owners and sellers are 
free to transact through contracts of whatever length they find 
mutually agreeable.
    196. Shell Energy's suggestion that Energy Imbalance and Generator 
Imbalance services be combined into a single product is beyond the 
scope of this rulemaking, and Shell Energy's arguments in support of 
this idea do not rise to a level concrete enough to justify such an 
expansion at this time.
    197. With respect to Shell Energy and EPSA's comments regarding 
recognition of non-contingency-related balancing reserves as separate 
from ancillary services, and WSPP's similar discussion of ``flexible 
capacity,'' we clarify that sales of energy and capacity at market-
based rates are permissible, provided the buyer may not use the 
purchases to meet its OATT obligations to provide Regulation and 
Frequency Response or Reactive Supply and Voltage Control ancillary 
services.
    198. AWEA's comments regarding dynamic transfer capability raise 
issues beyond the scope of this rulemaking, which have not been fully 
explored in this proceeding, and whose resolution is not necessary to 
the completion of this rulemaking. Accordingly, the Commission will not 
direct changes with respect to dynamic scheduling or dynamic transfer 
capability at this time.
    199. Regarding Powerex's argument for development of a new market 
liquidity screen for ancillary service market power, we decline to 
attempt such development at this time. The record does not currently 
support either development of a generic market liquidity metric, or the 
particular minimum participant number thresholds proposed by Powerex. 
We remain open to a more detailed discussion of these ideas in the 
future if needed, but at this time will move forward with the rule 
changes contained elsewhere in this Final Rule, which we hope will 
reduce the need to develop alternative market power analyses.

III. Summary of Compliance and Implementation

BILLING CODE 6717-01-P

[[Page 46206]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.004

[[Page 46207]]

[GRAPHIC] [TIFF OMITTED] TR30JY13.005

BILLING CODE 6717-01-C
    201. While the authorization is effective as of the date specified 
in this Final Rule, sellers should file this tariff revision the next 
time they make a market-based rate filing with the Commission. To the 
extent sellers do not currently have this provision in their tariff but 
wish to make third-party sales of ancillary services, they should 
include this revised provision in their tariff the next time they make 
a market-based rate filing with the Commission.
    202. With regard to sales of Operating Reserves, as discussed 
above, both sellers that have a market-based rate tariff on file and 
applicants seeking new market-based rate authority must satisfactorily 
make the required showing and receive Commission authorization before 
making sales of Operating Reserve-Spinning and Operating Reserve-
Supplemental to a public utility that is purchasing Operating Reserve-
Spinning and Operating Reserve-Supplemental to satisfy its own open 
access transmission tariff requirements to offer ancillary services to 
its own customers.
    203. With respect to the Final Rule's reforms to provide greater 
transparency with regard to reserve requirements for Regulation and 
Frequency Response, within 30 days from the effective date of this 
Final Rule, we require each public utility transmission provider to 
revise its OATT Schedule 3 consistent with the revised Schedule 3 in 
accordance with Appendix B to this Final Rule.
    204. With respect to Final Rule's reforms to our accounting and 
reporting regulations, utilities subject to these requirements must 
implement the requirements as of January 1, 2013. Utilities are not 
required to adjust prior year, comparative information reported in 2013 
Form Nos. 1 and 1-F that must be filed by April 18, 2014, nor are they 
required to adjust prior year, comparative information reported in 2013 
Form No. 3-Q reports. However, a footnote disclosure must be provided 
describing any amounts transferred from an existing account to a new 
energy storage account.
    205. Due to outdated software, discussed in more detail in the body 
of this Final Rule, the adopted new and revised schedules of Form Nos. 
1, 1-F and 3-Q will not be available for use as of the effective date 
of this Final Rule. Consequently, utilities with energy storage assets 
and those that acquire the assets at a later date must continue or 
begin, as appropriate, using the existing form schedules to report 
energy storage assets pending availability of the new and revised 
schedules.

IV. Information Collection Statement

    206. The following collections of information contained in this 
Final 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.\229\ OMB's regulations require approval of certain information 
collection requirements imposed by agency rule.\230\ Upon approval of a 
collection of information, OMB will assign an OMB control number and an 
expiration date. Respondents subject to the filing requirements of a 
rule will not be penalized for failing to respond to these collections 
of information if the collections of information do not display a valid 
OMB control number.
---------------------------------------------------------------------------

    \229\ See 44 U.S.C. 3507(d).
    \230\ 5 CFR 1320.11 (2012).
---------------------------------------------------------------------------

    Burden Estimate: The additional estimated public reporting burdens 
and costs for the reporting requirements in this Final Rule are as 
follows.\231\
---------------------------------------------------------------------------

    \231\ In the NOPR, the Commission proposed changes to FERC-919 
(related to the `20 percent screen'). The FERC-919 is not affected 
by the Final Rule. In addition, changes to FERC-516, which were not 
contained in the NOPR, are included in the Final Rule.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                             Change in  the total
                                                              Change in the number                            annual hours  for      Estimated  annual
                                                               of hours per filing        Filings per          this  collection       cost  (averaging
          Data collection            Number of  respondents        (averaging         respondent  per year        (averaging        implementation over
                                               (a)             implementation over            (c)            implementation over    Yrs. 1-3)  (at $120/
                                                              Yrs. 1-3) \232\  (b)                           Yrs. 1-3)  (aXbXc=d)    hr.)  (dX$120/hr.)
                                                                     (hrs.)                                         (hrs.)                  ($)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Form No. 1.........................  210...................  7 [3 hrs. (one-time     1....................  1,470................  176,400
                                                              implementation in
                                                              Year 1), plus 6 hrs.
                                                              annually].
Form No. 1-F.......................  5.....................  7 [3 hrs. (one-time     1....................  35...................  4,200
                                                              implementation in
                                                              Year 1), plus 6 hrs.
                                                              annually].
Form No. 3-Q.......................  213...................  1.....................  3....................  639..................  76,680
FERC-917 [includes one-time filing   132...................  17.33 averaged over     1....................  2,288 averaged over    274,560 averaged over
 of Pro forma open-access                                     Years 1-3 [4 hrs. one-                         Years 1-3.             Years 1-3
 transmission tariff (OATT) & data                            time in Yr. 1, plus
 sharing] \233\.                                              an average recurring
                                                              burden in Years 1-3
                                                              of 16 hrs.].
FERC-516...........................  no change.............  no change.............  no change............  no change............  no change

[[Page 46208]]

 
FERC-717 (OASIS posting under 18     176...................  1.....................  1....................  176..................  9,889 \234\
 CFR 37.6k).
    Total..........................  ......................  ......................  .....................  4,608 (averaged over   $541,729 (averaged
                                                                                                             Years 1-3).            over Years 1-3)
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

    \232\ For the Forms 1 and 1-F, the one-time implementation 
burden in Year 1 is estimated to be 3 hours per respondent. However, 
for the burden and cost estimates, we are averaging those additional 
3 hours over Years 1-3, giving an average annual one-time 
implementation burden of 1 hour. That 1 hour is in addition to the 
normal annual filing burden of 6 hours each, giving an average 
annual estimate of 7 hours for Forms 1 and 1-F, for Years 1-3.
    \233\ This includes the one-time refiling of OATT Schedule 3 
(estimated average of 4 hours per utility respondent), and if 
requested, the utility's sharing data and a narrative description 
with its self-supplying customer(s) (estimated average of 4 customer 
requests per utility respondent per year, taking 4 hours per 
request). The estimated annual burden per utility is
     Year 1: 4 hrs. (for one-time refiling) + (4 requests * 
4 hrs.), giving an estimate of 20 hrs. per utility
     Years 2 and 3, each: 4 requests * 4 hrs., giving 16 
hrs. per utility per year. When the one-time implementation burden 
(of 4 hours) is averaged over Years 1-3, the annual additional 
burden per utility is 17.33 hours.
    \234\ Based on the 2012 data from the Bureau of Labor Statistics 
at http://bls.gov/oes/current/naics2_22.htm, the hourly cost of 
salary plus benefits would be $56.19.
---------------------------------------------------------------------------

    In paragraph 96, the Commission is requiring that any third-party 
seller seeking to sell ancillary services to a public utility 
transmission provider through a competitive solicitation will need to 
demonstrate compliance with the competitive solicitation requirements 
of this rule, through a filing under section 205 of the Federal Power 
Act. This requirement for submittal in a section 205 filing would be 
made under FERC-516 (OMB Control No. 1902-0096). The filing would be 
submitted by the seller to the Commission prior to commencement of 
service under the third-party ancillary service sales agreement that 
results from the competitive solicitation. The filing will include both 
the actual sales agreement and a narrative description of how the 
buyer's competitive solicitation meets the requirements of this Final 
Rule. Meeting those requirements demonstrates the justness and 
reasonableness of the resulting rate. If the seller did not have this 
option to sell under the competitive solicitation, the seller could not 
use market-based rates and would have to either submit an application 
for cost-based rates under FERC-516 or an application seeking waiver of 
the Avista restrictions on a case-by-case basis.\235\ The Commission 
believes that the burden associated with the new requirements is far 
less burden than a full cost-of-service rate filing and approximately 
the same burden as the burden associated with an Avista waiver filing. 
In addition, the numbers of respondents and filings are not expected to 
change significantly. Therefore, no changes are proposed to the burden 
or number of responses for FERC-516.
---------------------------------------------------------------------------

    \235\ See, e.g., Powerex, 125 FERC ] 61,179 (2008).
---------------------------------------------------------------------------

    Title: 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-516, '' Electric Rate Schedules and Tariff 
Filings,'' and FERC-717, ``Open Access Same-Time Information System and 
Standards for Business Practices & Communication Protocols.''
    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-
0096 (FERC-516), and 1902-0173 (FERC-717).
    Respondents: Businesses or other for profit and/or not-for-profit 
institutions.
    Frequency of responses: Annually (FERC Form Nos. 1 and 1-F, and 
FERC-717); quarterly (FERC Form No. 3-Q); and as needed (FERC-917 and 
FERC-516).
    Necessity of the Information: The final rule amends the 
Commission's regulations to reflect changes that are occurring in the 
electric industry due to the availability of new energy storage 
technologies that are being used in the provision of large-scale 
utility operations. These technologies are providing services that were 
typically provided by traditional single-purpose production, 
transmission and distribution resources. The addition of these new 
plant accounts and new and amended reporting forms are intended to 
enhance transparency and provide detailed information on transactions 
and events affecting public utilities and licensees that file reports 
with the Commission. The accounting regulations currently found in the 
USofA and related reporting requirements capture financial and 
operational information along traditional primary business functions 
but do not provide sufficient detailed information concerning energy 
storage operations, and in particular, the costs incurred by 
organizations using these resources to simultaneously provide multiple 
utility services with a single asset. The addition of these accounts is 
intended to improve the transparency, completeness and consistency of 
accounting practices for the cost of assets, the expenses incurred in 
providing services, along with revenues collected. Without specific 
instructions and accounts for recording and reporting the above 
transactions and events, inconsistent and incomplete accounting and 
reporting will result.
    Internal Review: The Commission has reviewed the requirements 
pertaining to the USofA and to 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 the expenses incurred for providing 
services as part of its operations.
    These requirements conform to the Commission's need for efficient 
information collection, communication, and management within the energy 
industry. The Commission has assured itself, by means of internal 
review, that there is specific, objective support for

[[Page 46209]]

the burden estimates associated with the information collection 
requirements.
    Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street NE., Washington, DC 20426 [Attention: 
Ellen Brown, Office of the Executive Director], email: 
DataClearance@ferc.gov, Phone (202) 502-8663, fax: (202) 273-0873.
    Comments on the collection of information and the associated burden 
estimates in the rule should be sent to the Commission in this docket 
and may also be sent to the Office of Information and Regulatory 
Affairs, Office of Management and Budget, Washington, DC 20503 
[Attention: Desk Officer for the Federal Energy Regulatory Commission]. 
For security reasons, comments to OMB should be submitted by email to: 
oira_submission@omb.eop.gov. Please refer to OMB Control Nos. 1902-
0021 (FERC Form No. 1), 1902-0029 (FERC Form No. 1-F), 1902-0205 (FERC 
Form No. 3-Q), and 1902-0233 (FERC-917), 1902-0096 (FERC-516), and 
1902-0173 (FERC-717) and Docket Number RM11-24.

Environmental Analysis

    207. 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.\236\ 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.\237\
---------------------------------------------------------------------------

    \236\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 
Regulations Preambles 1986-1990 ] 30,783 (1987).
    \237\ 18 CFR 380.4(a)(15) (2012).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act

    208. The Regulatory Flexibility Act of 1980 (RFA) \238\ generally 
requires a description and analysis of 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) Office of Size Standards develops the 
numerical definition of a small business.\239\ 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.\240\ The 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 2011 annual 
FERC Form No. 1 and Form No. 1-F, as well as the number of companies 
that have obtained waivers, we estimate that 44 entities (20 percent of 
the filers) affected by this proposed rule are ``small.'' For each of 
the 44 ``small'' entities, the Commission estimates an additional 
annual burden of only ten hours (seven hours for the annual Form 1 or 
Form 1-F (averaging implementation over years 1-3), plus one hour per 
quarter for the Form 3-Q). 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.
---------------------------------------------------------------------------

    \238\ 5 U.S.C. 601-612.
    \239\ 13 CFR 121.101 (2011).
    \240\ 13 CFR 121.201, Sector 22, Utilities.
---------------------------------------------------------------------------

VII. Document Availability

    209. 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.
    210. 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.
    211. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from the Commission's Online 
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202)502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.
    Effective Date and Congressional Notification. These regulations 
are effective November 27, 2013. The Commission has determined, with 
the concurrence of the Administrator of the Office of Information and 
Regulatory Affairs of OMB, that this rule is not a ``major rule'' as 
defined in section 351 of the Small Business Regulatory Enforcement 
Fairness Act of 1996.

List of Subjects

18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements

18 CFR Part 101

    Electric power, Electric utilities, Uniform System of Accounts.

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

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

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
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. 9701; 42 
U.S.C. 7101-7352.

0
2. Amend Sec.  35.37 by revising paragraph (c)(1) to read as follows:

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, and generator imbalance services 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 lacks horizontal market power with respect to sales of 
operating reserve-spinning and operating reserve-supplemental services 
if the Seller passes these two indicative market power screens and 
demonstrates in its market-based rate application how the scheduling 
practices in its region

[[Page 46210]]

support the delivery of operating reserve resources from one balancing 
authority area to another. There will be a rebuttable presumption that 
a seller possesses horizontal market power with respect to sales of 
energy, capacity, energy imbalance, generator imbalance, operating 
reserve-spinning, and operating reserve-supplemental services if it 
fails either screen.
* * * * *

0
3. Amend Sec.  35.38 as follows:
0
a. Paragraph (a) is revised.
0
b. Paragraph (b) introductory text is revised.
0
c. Paragraph (c) is added.
    The revisions and addition read as follows:

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 consist of: 
(1) A cap based on the relevant OATT ancillary service rate of the 
purchasing transmission operator; or (2) the results of a competitive 
solicitation that meets the Commission's requirements for transparency, 
definition, evaluation, and competitiveness.

0
4. Amend Sec.  37.6 by adding paragraph (k) to read as follows:

Sec.  37.6  Information to be posted on the OASIS.

* * * * *
    (k) Posting of historical area control error data. The Transmission 
Provider must post on OASIS historical one-minute and ten-minute area 
control error data for the most recent calendar year, and update this 
posting once per year.

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

0
5. 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.

0
6. In Part 101:
0
a. Under Electric Plant Chart of Accounts, Account 348 is added to the 
list;
0
b. Under Electric Plant Accounts, Account 351, the name of the account 
is revised and instructions are added;
0
c. Under Electric Plant Accounts, Account 363, the name of the account 
and the instructions are revised;
0
d. Under Electric Plant Accounts, primary plant account 348 is added;
0
e. Under Operation and Maintenance Expense Chart of Accounts, Accounts 
548.1, 553.1, 555.1, 562.1, 570.1, 584.1, and 592.2 are added to the 
list;
0
f. Under Operation and Maintenance Expense Accounts, operation expense 
account 548.1 is added;
0
g. Under Operation and Maintenance Expense Accounts, maintenance 
expense account 553.1 is added;
0
h. Under Operation and Maintenance Expense Accounts, power supply 
expense account 555.1 is added;
0
i. Under Operation and Maintenance Expense Accounts, operation expense 
account 562.1 is added;
0
j. Under Operation and Maintenance Expense Accounts, maintenance 
expense account 570.1 is added;
0
k. Under Operation and Maintenance Expense Accounts, operation expense 
account 584.1 is added;
0
l. Under Operation and Maintenance Expense Accounts, maintenance 
expense account 592.2 is revised; and
0
m. Under Operation and Maintenance Expense Accounts, maintenance 
expense account 592.1 is revised;
    The revisions and additions read as follows:

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

* * * * *

Electric Plant Chart of Accounts

* * * * *

2. Production Plant

* * * * *

D. Other Production

* * * * *
348 Energy Storage Equipment--Production
* * * * *

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 purposes, 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 purchased to 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
* * * * *
    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 purchased to energize the equipment are 
includible

[[Page 46211]]

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, 592.1, 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
* * * * *
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 purchased to 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 accounts 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.
* * * * *

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
* * * * *
584.1 Operation of Energy Storage Equipment
* * * * *
Maintenance
* * * * *
592.2 Maintenance of Energy Storage Equipment
* * * * *

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.
* * * * *
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.
* * * * *
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.
* * * * *
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

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not specifically provided for or are readily assignable to other 
transmission operation 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.
* * * * *
584.1 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.
* * * * *
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.
* * * * *
592 Maintenance of Station Equipment (Major Only)
    This account shall include the cost of labor, materials used and 
expenses incurred in maintenance of plant, the book cost of which is 
includible in account 362, Station Equipment. (See operating expense 
instruction 2.)
* * * * *
592.1 Maintenance of Structures and Equipment (Nonmajor Only)
    This account shall include the cost of labor, materials used and 
expenses incurred in maintenance of structures, the book cost of which 
is includible in account 361, Structures and Improvements, and account 
362, Station Equipment. (See operating expense instruction 2.)

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

Appendix A: List of Short Names of Commenters on the Federal Energy 
Regulatory Commission's Notice of Proposed Rulemaking on Third-Party 
Provision of Ancillary Services; Accounting and Financial Reporting for 
New Electric Storage Technologies--Docket No. RM11-24-000, June 2012

------------------------------------------------------------------------
    Short name or acronym                      Commenter
------------------------------------------------------------------------
APPA.........................  American Public Power Association
AWEA.........................  American Wind Energy Association
Beacon.......................  Beacon Power Corporation
California PUC...............  California Public Utilities Commission
California Storage Alliance..  California Energy Storage Alliance
EEI..........................  Edison Electric Institute
Electricity Consumers........  Electricity Consumers Resource Council
ENBALA.......................  ENBALA Power Networks
EPSA.........................  Electric Power Supply Association
ESA..........................  Electricity Storage Association
FTC Staff....................  Staff of the Federal Trade Commission
Hydro Association............  National Hydropower Association
Iberdrola....................  Iberdrola Renewables, LLC
Indicated Suppliers..........  Calpine Corporation, Dynegy Inc., Exelon
                                Corporation, GenOn Energy, Inc., and
                                Tenaska Energy, Inc.
Midwest ISO..................  Midwest Independent Transmission System
                                Operator Inc.
Morgan Stanley...............  Morgan Stanley Capital Group Inc.
NAATBatt.....................  National Alliance for Advanced Technology
                                Batteries
New York ISO.................  New York Independent System Operator,
                                Inc.
NU Companies.................  Northeast Utilities Service Company on
                                behalf of Connecticut Light and Power
                                Company, Western Massachusetts Electric
                                Company, Public Service Company of New
                                Hampshire, and NSTAR Electric Company
Powerex......................  Powerex 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
Public Power Council.........  Public Power Council
SDG&E........................  San Diego Gas & Electric Company
Shell Energy.................  Shell Energy North America (US), L.P.
Solar Energy Association.....  Solar Energy Industries Association
Southern California Edison...  Southern California Edison Company
TAPS.........................  Transmission Access Policy Study Group
                                and Transmission Dependent Utility
                                Systems
Western Group................  Arizona Public Service, Avista
                                Corporation, Bonneville Power
                                Administration, Idaho Power Company,
                                PacifiCorp, Portland General Electric,
                                Xcel Energy Services, Puget Sound
                                Energy, Inc., Seattle City Light, and
                                Takoma Power
WSPP.........................  WSPP, Inc.
------------------------------------------------------------------------

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

Appendix B: Pro Forma Open Access Transmission Tariff

    The Commission amends Schedule 3, Regulation and Frequency Response 
Service of the pro forma OATT:

Schedule 3

Regulation and Frequency Response Service

    Regulation and Frequency Response Service is necessary to provide 
for the continuous balancing of resources

[[Page 46213]]

(generation and interchange) with load and for maintaining scheduled 
Interconnection frequency at sixty cycles per second (60 Hz). 
Regulation and Frequency Response Service is accomplished by committing 
on-line generation whose output is raised or lowered (predominantly 
through the use of automatic generating control equipment) and by other 
non-generation resources capable of providing this service as necessary 
to follow the moment-by-moment changes in load. The obligation to 
maintain this balance between resources and load lies with the 
Transmission Provider (or the Control Area operator that performs this 
function for the Transmission Provider). The Transmission Provider must 
offer this service when the transmission service is used to serve load 
within its Control Area. The Transmission Customer must either purchase 
this service from the Transmission Provider or make alternative 
comparable arrangements to satisfy its Regulation and Frequency 
Response Service obligation. The Transmission Provider will take into 
account the speed and accuracy of regulation resources in its 
determination of Regulation and Frequency Response reserve 
requirements, including as it reviews whether a self-supplying 
Transmission Customer has made alternative comparable arrangements. 
Upon request by the self-supplying Transmission Customer, the 
Transmission Provider will share with the Transmission Customer its 
reasoning and any related data used to make the determination of 
whether the Transmission Customer has made alternative comparable 
arrangements. The amount of and charges for Regulation and Frequency 
Response Service are set forth below. To the extent the Control Area 
operator performs this service for the Transmission Provider, charges 
to the Transmission Customer are to reflect only a pass-through of the 
costs charged to the Transmission Provider by that Control Area 
operator.

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

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[FR Doc. 2013-17746 Filed 7-29-13; 8:45 am]
BILLING CODE 6717-01-C