139 FERC ¶ 61,245

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Parts 35, 101 and 141

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

Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for 

New Electric Storage Technologies

(June 22, 2012)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of Proposed Rulemaking.

SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes to 

revise certain aspects of its current market-based rate regulations, ancillary services 

requirements under the pro forma open-access transmission tariff (OATT), and 

accounting and reporting requirements. Specifically, the Commission proposes to revise 

its Avista Corp.1 policy governing the sale of ancillary services at market-based rates to 

public utility transmission providers and reflect such reforms in Parts 35 and 37 of the 

Commission’s regulations. The Commission also proposes to require each public utility 

transmission provider to include provisions in its OATT explaining how it will determine 

Regulation and Frequency Response reserve requirements in a manner that takes into 

account the speed and accuracy of resources used. Finally, the Commission proposes to 

 1 See Avista Corp., 87 FERC ¶ 61,223 (Avista), order on reh’g, 89 FERC ¶ 61,136 

(1999). 
Docket Nos. RM11-24-000 and AD10-13-000 - 2 -

revise the accounting and reporting requirements under its Uniform System of Accounts 

for public utilities and licensees and its forms, statements, and reports, contained in 

FERC Form No. 1, Annual Report of Major Electric Utilities, Licensees and Others, 

FERC Form No. 1-F, Annual Report for Nonmajor Public Utilities and Licensees, and 

FERC Form No. 3-Q, Quarterly Financial Report of Electric Utilities, Licensees, and 

Natural Gas Companies, to better account for and report transactions associated with the 

use of energy storage devices in public utility operations.

DATES: Comments are due 60 days after publication in the FEDERAL REGISTER.

ADDRESSES: Comments, identified by docket number, may be filed in the following 

ways:

• Electronic Filing through http://www.ferc.gov. Documents created electronically

using word processing software should be filed in native applications or print-toPDF format and not in a scanned format.

• Mail/Hand Delivery: Those unable to file electronically may mail or hand-deliver 

comments to: Federal Energy Regulatory Commission, Secretary of the 

Commission, 888 First Street, NE, Washington, DC 20426.

Instructions: For detailed instructions on submitting comments and additional 

information on the rulemaking process, see the Comment Procedures Section of this 

document.

FOR FURTHER INFORMATION CONTACT:

Rahim Amerkhail (Technical Information)

Federal Energy Regulatory Commission, Office of Energy Policy and Innovation

888 First Street, NE

Washington, DC 20426

(202) 502-8266
Docket Nos. RM11-24-000 and AD10-13-000 - 3 -

Christopher Handy (Accounting Information)

Federal Energy Regulatory Commission, Office of Enforcement

888 First Street, NE

Washington, DC 20426

(202) 502-6496

Lina Naik (Legal Information)

Federal Energy Regulatory Commission, Office of the General Counsel

888 First Street, NE

Washington, DC 20426

(202) 502-8882

Eric Winterbauer (Legal Information)

Federal Energy Regulatory Commission, Office of the General Counsel

888 First Street, NE

Washington, DC 20426

(202) 502-8329

SUPPLEMENTARY INFORMATION:
139 FERC ¶ 61,245

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Third-Party Provision of Ancillary Services; Accounting 

and Financial Reporting for New Electric Storage 

Technologies

Docket Nos. RM11-24-000

AD10-13-000

NOTICE OF PROPOSED RULEMAKING

(June 22, 2012)

1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory 

Commission (Commission) seeks comment on a package of related proposals developed 

by the Commission based on comments received in response to a Notice of Inquiry (NOI)2

issued in this proceeding on June 16, 2011. As the Commission noted in the NOI, there is 

growing interest in rate flexibility by both purchasers and sellers of ancillary services. A 

variety of resources are poised to provide ancillary services but may be frustrated from 

doing so by certain aspects of the Commission’s market-based rate policies. At the same 

time, transmission customers and sellers alike are seeking greater transparency with regard 

to reserve requirements for ancillary services, with a particular focus on Regulation and 

Frequency Response. As the Commission has considered ways to foster transparency and 

competition in ancillary services markets, issues also have arisen related to accounting for 

and reporting of sales from energy storage devices that, if left unresolved, could impair the 

ability of these resources to participate in markets for ancillary services and other services 

subject to the Commission’s jurisdiction. 

 2 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting 

for New Electric Storage Technologies, 135 FERC ¶ 61,240 (2011) (NOI).
Docket Nos. RM11-24-000 and AD10-13-000 - 2 -

2. The NOI explored these topics by seeking comment on existing restrictions on 

third-party provision of ancillary services, irrespective of the technologies used for such 

provision. The NOI also questioned whether the various cost-based compensation 

methods for Regulation and Frequency Response service that exist in regions outside of 

the current organized markets could be adjusted to address the same speed and accuracy 

issues identified in the proceeding that led to the issuance of Order No. 755.3

 Finally, the 

NOI sought comment on the adequacy of current accounting and reporting requirements as 

they pertain to the oversight of the provision of jurisdictional services from energy storage 

devices.

3. Based on the comments received in response to the NOI, the Commission proposes 

to revise certain aspects of its market-based rate regulations, ancillary services 

requirements under the pro forma open-access transmission tariff (OATT), and accounting 

and reporting requirements. Specifically, the Commission proposes to revise its Avista

Corp. policy governing the sale of ancillary services at market-based rates to public utility 

transmission providers and reflect such reforms in Parts 35 and 37 of the Commission’s 

regulations.4

 The Commission also proposes to require each public utility transmission 

provider to include provisions in its OATT explaining how it will determine Regulation 

and Frequency Response service reserve requirements in a manner that takes into account 

 3 Frequency Regulation Compensation in the Organized Wholesale Power Markets, 

Order No. 755, FERC Stats. & Regs. ¶ 31,324 (2011), reh’g denied, Order No. 755-A, 138 

FERC ¶ 61,123 (2012).

4 See Avista Corp., 87 FERC ¶ 61,223 (Avista), order on reh’g, 89 FERC ¶ 61,136 

(1999) (Avista Rehearing Order). 
Docket Nos. RM11-24-000 and AD10-13-000 - 3 -

the speed and accuracy of resources used. Finally, the Commission proposes to revise 

certain accounting and reporting requirements under its Uniform System of Accounts for 

public utilities and licensees (USofA)5 and its forms, statements, and reports, contained in 

FERC Form No. 1 (Form No. 1), Annual Report of Major Electric Utilities, Licensees and 

Others,

6 FERC Form No. 1-F (Form No. 1-F), Annual Report for Nonmajor Public 

Utilities and Licensees,

7 and FERC Form No. 3-Q (Form No. 3-Q), Quarterly Financial 

Report of Electric Utilities, Licensees, and Natural Gas Companies,8 to better account for 

and report transactions associated with energy storage devices used in public utility 

operations. The Commission seeks comment on these proposed reforms. 

I. Background

4. The Commission has initiated numerous actions over the last several decades to 

foster the development of competitive wholesale energy markets by ensuring nondiscriminatory access and comparable treatment of resources in jurisdictional wholesale 

markets.9

 With regard to ancillary services, the Commission in Order No. 88810

 5 Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject 

to the Provisions of the Federal Power Act, 18 CFR Part 101 (2011).

6 18 CFR § 141.1 (2011). 

7 18 CFR § 141.2 (2011).

8 18 CFR § 141.400 (2011).

9 See, e.g., Promoting Wholesale Competition Through Open Access NonDiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by 

Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036, 

at 31,781 (1996), order on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order 

on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 

82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy 

(continued...)
Docket Nos. RM11-24-000 and AD10-13-000 - 4 -

contemplated that third parties (i.e., parties other than a transmission provider supplying 

ancillary services pursuant to its OATT obligation) could provide ancillary services on 

other than a cost-of-service basis if such pricing was supported, on a case-by-case basis, 

by analyses that demonstrated that the seller lacks market power in the relevant product 

market.

11 Later, in Ocean Vista Power Generation, L.L.C.,12 the Commission provided 

guidance regarding such analyses, explaining that as a general matter a study of ancillary 

services markets should address the nature and characteristics of each ancillary service, as 

 

Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 

535 U.S. 1 (2002); Market-Based Rates for Wholesale Sales of Electric Energy, Capacity 

and Ancillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252,

clarified, 121 FERC ¶ 61,260 (2007), order on reh’g, Order No. 697-A, FERC Stats. & 

Regs. ¶ 31,268, clarified, 124 FERC ¶ 61,055, order on reh’g, Order No. 697-B, FERC 

Stats. & Regs. ¶ 31,285 (2008), order on reh’g, Order No. 697-C, FERC Stats. & Regs. 

¶ 31,291 (2009), order on reh’g, Order No. 697-D, FERC Stats. & Regs. ¶ 31,305 (2010), 

aff’d sub nom. Montana Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011); 

Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 

FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC Stats. & Regs. 

¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on 

reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on reh’g, Order No. 890-D, 

129 FERC ¶ 61,126 (2009); Wholesale Competition in Regions with Organized Electric 

Markets, Order No. 719, FERC Stats. & Regs. ¶ 31,281 (2008), order on reh’g, Order No. 

719-A, FERC Stats. & Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719-B, 129 

FERC ¶ 61,252 (2009).

10 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,781.

11 Order No. 888 required six Ancillary Services to be included in the OATT: 1)

Scheduling, System Control and Dispatch; 2) Reactive Supply and Voltage Control from 

Generation Sources; 3) Regulation and Frequency Response; 4) Energy Imbalance; 5)

Operating Reserve-Spinning; and 6) Operating Reserve-Supplemental. Order No. 890 

later added a seventh OATT ancillary service: Generator Imbalance. See Order No. 890,

FERC Stats. & Regs. ¶ 31,241 at P 85.

12 82 FERC ¶ 61,114, at 61,406-07 (1998) (Ocean Vista).
Docket Nos. RM11-24-000 and AD10-13-000 - 5 -

well as the nature and characteristics of generation capable of supplying each service, and 

that the study should develop market shares for each service.

5. The Commission subsequently acknowledged in Avista13 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 services14 at market-based rates with certain 

restrictions.15 In so doing, the Commission reasoned that the backstop of cost-based

ancillary services from transmission providers, in effect, limits the price at which 

customers are willing to buy ancillary services, thus ensuring that the third party sellers’ 

rates would remain just and reasonable even without a showing of lack of market power. 

However, the Commission found that this backstop failed to provide adequate mitigation 

 13 Avista, 87 FERC at 61,882.

14 These ancillary services included: Regulation and Frequency Response, Energy 

Imbalance, Operating Reserve-Spinning, and Operating Reserve-Supplemental. The 

Commission did not extend this Avista policy to Reactive Supply and Voltage Control 

from Generation Sources service, which means that third parties wishing to sell this 

ancillary service at market-based rates would remain subject to the pre-Avista market 

power screen requirement. The Commission also did not extend the Avista policy to 

Scheduling, System Control and Dispatch service. However, because only balancing area 

operators can provide this ancillary service, it does not lend itself to competitive supply.

15 One of the restrictions imposed in Avista was an obligation for sellers to establish 

an internet-based website for providing information about and transacting ancillary 

services and on-going reports to the Commission detailing their activities in the ancillary 

services markets. See Avista, 87 FERC at 61,883. In Order No. 697, the Commission 

concluded that subsequent implementation of electric quarterly report (EQR) filing 

requirements justified eliminating these requirements under the Avista policy. 
Docket Nos. RM11-24-000 and AD10-13-000 - 6 -

of potential third-party market power in three situations: (1) sales to an RTO or an ISO, 

which has no ability to self-supply ancillary services but instead depends on third parties;16

(2) to address affiliate abuse concerns, sales to a traditional, franchised public utility 

affiliated with the third-party supplier, or sales where the underlying transmission service 

is on the system of the public utility affiliated with the third-party supplier; and (3) sales to 

a public utility that is purchasing ancillary services to satisfy its own OATT requirements 

to offer ancillary services to its own customers.17 

6. The Commission’s focus in this proceeding is on the third situation above. The 

concern in this situation has been that if third parties who had not been shown to lack 

market power were permitted to sell to public utilities seeking to meet their OATT 

ancillary service obligations, the public utility’s ability to recover such purchase costs in 

OATT rates might lead it to agree to above-market purchases, which would then be 

incorporated into the public utility’s OATT ancillary service rate and gradually increase 

that rate. This increase in turn would reduce the ability of the cost-based OATT rate to 

serve as an alternative to the third-party market based rate, and thus undermine the 

mitigation measure that the Commission relied upon in Avista to enable relaxation of the 

 16 Subsequently, as the Commission recognized in Order No. 697, most RTOs and 

ISOs developed formal ancillary service markets, thus rendering this component of the 

Avista policy largely superfluous. See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 

n.1194 and P 1069. 

17 Avista, 87 FERC ¶ 61,223 at n.12.
Docket Nos. RM11-24-000 and AD10-13-000 - 7 -

requirement for a market power analysis.18 In summary, under existing Commission 

regulation and policy, a third-party supplier may sell certain ancillary services at marketbased rates without showing a lack of market power except under the three circumstances 

identified above. 

7. Over a decade has passed since the Commission first developed the Avista

restrictions. During this time, potential changes to the Avista restrictions have been 

considered by the Commission on several occasions. In the rulemaking proceeding 

leading to the issuance of Order No. 697, the Commission sought comment on whether to 

modify or revise the Avista policy and, if so, how.19 The Commission ultimately retained 

its policy of not allowing sales of ancillary services by a third-party supplier in the three 

situations identified above, but noted its openness to considering requests for market-based 

rate authorization to make such sales on a case-by-case basis.20 Such a request was 

submitted by WSPP in 2011. Based on the facts in that instance, the Commission rejected 

WSPP’s request as it related to market-based sales by a third-party supplier to satisfy the 

purchasing transmission provider’s own OATT requirements to offer ancillary services to 

its customers. However, the Commission noted that it was open to new approaches in the

 18 See Avista Rehearing Order, 89 FERC at 61,391-92 (stating that the Commission 

is “able to grant blanket authority for flexible pricing only because the price charged by 

the third-party supplier is disciplined by the obligation of the transmission provider to 

offer these services under cost-based rates. This discipline would be thwarted if the 

transmission provider could substitute purchases under non-cost-based rates for its 

mandatory service obligation.”) 

19 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 1052.

20 Id. P 1061.
Docket Nos. RM11-24-000 and AD10-13-000 - 8 -

evaluation of proposals for sales of ancillary services at market-based rates and 

encouraged parties to submit proposals that address the Commission’s concerns.21

8. In its ongoing effort to foster the development of competitive markets, including 

those for ancillary services, the Commission has continued to evaluate its Avista policy, in 

particular the restriction on the sale of ancillary services by third-parties to a public utility 

that is purchasing ancillary services to satisfy its own OATT requirements to offer 

ancillary services to its own customers. As the Commission considered potential revisions 

to the Avista policy, the Commission also has evaluated the extent to which other policies 

may impair development of ancillary services markets in light of a growing need for 

ancillary services to support grid functions in the face of potential changes in the portfolio 

of generation resources, entry of new technologies seeking to provide the service, and the 

growing interest of sellers and transmission providers to have flexibility in meeting 

ancillary services needs.22 

9. This evaluation led the Commission to issue an NOI in this proceeding to seek 

comment on whether revising this aspect of the Avista restriction would be appropriate, 

either by implementing alternative methods of proving a lack of market power or 

alternative methods of mitigating any potential market power. The NOI also sought 

comment on cost-based compensation methods for Regulation and Frequency Response 

 21 WSPP, Inc., 134 FERC ¶ 61,169 (2011).

22 See, e.g., Integration of Variable Energy Resources, Order No. 755, FERC Stats. 

& Regs. ¶ 32,664 (2010); and Demand Response Compensation in Organized Wholesale 

Energy Markets, Order No. 745, 76 FR 16658 (Mar. 24, 2011), FERC Stats. & Regs. 

¶ 31,322 (2011).
Docket Nos. RM11-24-000 and AD10-13-000 - 9 -

service, as well as accounting and reporting requirements as they pertain to oversight of 

the provision of jurisdictional services from energy storage devices. 

10. Based on the comments received, the Commission includes in this NOPR a package 

of proposals to facilitate the development of competitive markets for ancillary services, 

increase transparency for Regulation and Frequency Response reserve requirements, and 

better account for and report transactions associated with energy storage devices used in 

public utility operations. The Commission describes each of these proposals in detail 

below. 

II. Discussion

A. The Avista Policy

11. As noted above, the Commission’s Avista policy authorizes the sale of certain 

ancillary services at market-based rates without showing a lack of market power except 

under specified circumstances. As relevant here, a third-party may not sell ancillary 

services at market-based rates to a public utility that is purchasing ancillary services to 

satisfy its own open access transmission tariff requirements to offer ancillary services to 

its own customers. In order to overcome this restriction, a potential seller must provide a 

market power study demonstrating a lack of market power for the particular ancillary 

service in the particular geographic market. However, commenters in response to the NOI 

note that certain information needed to perform such a market power study is not currently 

available, effectively precluding them from the opportunity to make such a showing.23 

 23 WSPP Comments at 7-10, ENBALA Comments at 2-3, California Storage 

Alliance Comments at 5-6, and ESA Comments at 8.
Docket Nos. RM11-24-000 and AD10-13-000 - 10 -

Whether due to this or other limitations, the effect of the Avista policy is to categorically 

prohibit sales of ancillary services to public utility transmission providers outside of the 

RTO and ISO markets.24

12. Some commenters suggest that the current analyses used to evaluate a seller’s 

ability to exercise horizontal market power in the sale of energy and capacity remain 

sufficient to address market power in ancillary services as well.25 Other commenters 

contend that alternative mitigation measures would be appropriate for sellers unable to 

perform a market power analysis, such as the use of price caps based on the purchasing 

utility’s cost-based OATT ancillary services rates or the use of competitive solicitations.26 

The Commission believes that these suggestions may have merit and has developed 

potential reforms to the Avista policy to provide greater flexibility to sellers while 

protecting buyers from the exercise of market power that could lead to unjust and 

unreasonable or unduly discriminatory or preferential rates. These proposals are discussed 

further below. 

 24 As noted above, most RTOs and ISOs have developed formal ancillary service 

markets, allowing for the sale of ancillary services at market-based rates in those regions. 

25 PPL Companies Comments at 3, EPSA Comments at 5-6, and Portland General 

Comments at 3-4, Shell Energy Comments at 13-16, Powerex Comments at 38-40, and 

WSPP Comments at 11-12. While several commenters also support the idea of developing 

less challenging analyses for measuring ancillary service market power, none provides any 

concrete proposals. See, e.g., California PUC Comments at 5.

26 See, e.g., Southern California Edison Comments at 5-6 and WSPP Comments 

at 16.
Docket Nos. RM11-24-000 and AD10-13-000 - 11 -

1. Use of Market Power Analyses 

13. The Commission analyzes horizontal market power27 for sales of energy and 

capacity using two indicative screens, the wholesale market share screen and the pivotal 

supplier screen, to identify sellers that raise no horizontal market power concerns and can 

otherwise be considered for market-based rate authority.28 The wholesale market share 

screen measures whether a seller has a dominant position in the relevant geographic 

market in terms of the number of megawatts of uncommitted capacity owned or controlled 

by the seller, as compared to the uncommitted capacity of the entire market.29 A seller 

whose share of the relevant market is less than 20 percent during all seasons passes the 

wholesale market share screen.30 The pivotal supplier screen evaluates the seller’s 

potential to exercise horizontal market power based on the seller’s uncommitted capacity 

at the time of annual peak demand in the relevant market.31 A seller satisfies the pivotal 

supplier screen if its uncommitted capacity is less than the net uncommitted supply in the 

relevant market.32 

14. Passing both the wholesale market share screen and the pivotal supplier screen 

creates a rebuttable presumption that the seller does not possess horizontal market power; 

 27 18 CFR § 35.37 (b) (2011). 

28 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 13, 62. See also 18 CFR 

§ 35.37 (b), (c)(1) (2011).

29 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 43. 

30 Id. PP 43-44, 80, 89. 

31 18 CFR § 35.37 (c)(1) (2011). 

32 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 42. 
Docket Nos. RM11-24-000 and AD10-13-000 - 12 -

failing either screen creates a rebuttable presumption that the seller possesses horizontal 

market power.33 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.34 In the 

alternative, a seller may accept the presumption of horizontal market power and adopt 

some form of cost-based mitigation.35 

15. Three of the key components of the analysis of horizontal market power are the 

definition of products, the determination of appropriate geographic scope of the relevant 

market for each product, and the identification of the uncommitted generation supply 

within the relevant geographic market. In Order No. 697, the Commission adopted a 

default relevant geographic market for sales of energy and capacity.

36 In particular, the 

Commission will generally use a seller’s balancing authority area plus first-tier markets, or 

the RTO/ISO market as applicable, as the default relevant geographic market. However, 

where the Commission has made a specific finding that there is a submarket within an 

 33 18 CFR § 35.37 (c)(1) (2011). 

34 18 CFR § 35.37(c)(2) (2011). For purposes of rebutting the presumption of 

horizontal market power, sellers may use the results of the DPT to perform pivotal 

supplier and market share analyses and market concentration analyses using the 

Herfindahl-Hirschman Index (HHI). The HHI is a widely accepted measure of market 

concentration, calculated by squaring the market share of each firm competing in the 

market and summing the results. The Commission has stated that a showing of an HHI 

less than 2,500 in the relevant market for all season/load periods for sellers that have also 

shown that they are not pivotal and do not possess a market share of 20 percent or greater 

in any of the season/load periods would constitute a showing of a lack of horizontal

market power, absent compelling contrary evidence from intervenors. Order No. 697, 

FERC Stats. & Regs. ¶ 31,252 at P 111.

35 18 CFR § 35.37(c)(3) (2011). 

36 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 15.
Docket Nos. RM11-24-000 and AD10-13-000 - 13 -

RTO, that submarket becomes the default relevant geographic market for sellers located 

within the submarket for purposes of the market-based rate analysis. The Commission 

also provided guidance as to the factors the Commission will consider in evaluating 

whether, in a particular case, to adopt an alternative larger or smaller geographic market 

instead of relying on the default geographic market. A necessary condition that must be 

satisfied to justify an alternative market is a demonstration regarding whether there are 

frequently binding transmission constraints during historical peak seasons examined in the 

screens and at other competitive significant times that prevent competing supply from 

reaching customers within the proposed alternative geographic market.

37

16. For sales of energy and capacity, the product definitions are well understood, the 

relevant geographic market is generally the default market described above, and the 

uncommitted generation supply is generally identified as all such supply located within the 

seller’s balancing authority area plus potential uncommitted imports as determined largely 

by available transmission capacity in the form of simultaneous import limits.38 In contrast, 

defining the product, determining the relevant geographic market, and identifying 

uncommitted competing resources can be more complex for ancillary services. To date 

the Commission has not received an acceptable market power analysis for the sale of 

ancillary services at market-based rates outside of RTO/ISO markets. As noted above, 

 37 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 268.

38 Studies of Simultaneous Transmission Import Limits (SIL) quantify a study 

area’s simultaneous import capability from its aggregated first-tier area. SIL studies are 

used as a basis for calculating import capability to serve load in the relevant geographic

market when performing market power analyses.
Docket Nos. RM11-24-000 and AD10-13-000 - 14 -

certain commenters in response to the NOI contend that the information necessary to 

perform a market power analysis outside of RTO/ISO markets is not currently available.39 

Certain other commenters argue that the current analyses used to evaluate a seller’s ability 

to exercise market power in the sale of energy and capacity are sufficient to address 

market power in ancillary services as well.40 

17. Much of the difficulty in acquiring ancillary service-specific data is related to 

identifying specific resources that are physically capable of providing certain ancillary 

services. For instance, Schedule 6 Operating Reserve-Supplemental may be provided by 

generating units that are online but partially unloaded, by quick-start generating units that 

are offline or by interruptible load or other non-generation resources capable of providing 

this service.

41 The associated reliability standards definitions indicate that Operating 

Reserves – Supplemental must be fully available to serve load within the Disturbance 

Recovery Period, which by default is 15 minutes after a reportable disturbance.

42 

Information related to the amount of capacity able to start within 15 minutes and 

 39 WSPP Comments at 7-10; ENBALA Comments at 2-3; California Storage 

Alliance Comments at 5-6; and, ESA Comments at 8. Several of these commenters 

request that new reporting requirements be imposed to facilitate sellers’ ability to perform 

market power analyses for ancillary services markets. 

40 PPL Companies Comments at 3, EPSA Comments at 5-6, and Portland General 

Comments at 3-4, Shell Energy Comments at 13-16, Powerex Comments at 38-40, and 

WSPP Comments at 11-12.

41 See, e.g., Order No. 890-A, FERC Stats. & Regs. ¶ 31,261, Pro Forma OATT at 

Schedule 6, Operating Reserve – Supplemental Reserve Service.

42 See, e.g., NERC Reliability Standard BAL-002-1, Disturbance Control 

Performance at R4.2, available at http://www.nerc.com/files/BAL-002-1.pdf.
Docket Nos. RM11-24-000 and AD10-13-000 - 15 -

information related to the quantity of load that is interruptible within 15 minutes may not 

be readily available. In addition, the extent to which a public utility decides to provide this

service from partially loaded units is a decision that public utilities make on a day-to-day 

basis and is dictated in part by the amount of headroom available from the units that are 

committed and dispatched to serve and follow load. Information related to this kind of 

decision making is inherently difficult to obtain. This inability to obtain needed 

information coupled with the fact that certain ancillary services, as detailed further below, 

have geographic and other limitations gives rise to our interest in considering reforms 

based on the characteristics of the ancillary service to be provided.

a. Reliance on Existing Indicative Screens

18. In light of these issues associated with market power analyses for specific ancillary 

services, and the comments asserting that the existing market power analyses for sales of 

energy and capacity may be sufficient for ancillary services as well, the Commission has 

considered whether passing the existing market-based rate screens described above should 

create a rebuttable presumption that the seller lacks horizontal market power for ancillary 

services. As discussed below, the Commission believes that this may be the case for the 

two imbalance ancillary services (Energy Imbalance and Generator Imbalance), but that 

alternative definitions of the relevant geographic market and alternative assumptions for 

identifying potential competing resources within the relevant geographic market may be 

needed in order to apply the existing indicative screens to other ancillary services.

19. Units capable of providing Energy Imbalance and Generator Imbalance do not 

appear to require any different technical equipment or suffer from any different 

geographical limitations compared to units that provide energy or capacity. As one 
Docket Nos. RM11-24-000 and AD10-13-000 - 16 -

commenter argues, any available unit in a given geographic market would appear to be 

capable of providing energy that helps address imbalances in that market.43 The 

Commission notes that this position is consistent with the Commission’s decision in Order 

No. 890-A to base cost-based imbalance charges in the OATT on the incremental cost of 

the last 10 MW dispatched by the transmission provider for any purpose, without imposing 

any requirement that this last 10 MW be based on resources with any particular 

capabilities.

44 To the extent that there are no unique technical requirements or limitations 

that apply to the provision of Energy Imbalance or Generator Imbalance, it would follow 

that the market-based rate screens for energy and capacity would consider the same set of 

units as a market power analysis designed for those two ancillary services. 

20. Accordingly, the Commission proposes to revise its regulations governing marketbased rate authorizations to provide that sellers passing existing market-based rate 

analyses in a given geographic market should be granted a rebuttable presumption that 

they lack horizontal market power for sales of Energy Imbalance and Generator Imbalance 

ancillary services in that market. Specifically, section 35.37 of the Commission’s 

regulations would be revised to state that a seller would have a rebuttable presumption it 

lacks market power with respect to sales of energy, capacity, energy imbalance service, 

and generator imbalance service if the seller passes the pivotal supplier analysis based on 

annual peak demand of the relevant market and a market share analysis applied on a 

 43 Shell Energy Comments at 12.

44 See Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 309.
Docket Nos. RM11-24-000 and AD10-13-000 - 17 -

seasonal basis. The Commission preliminarily concludes that expanding the rebuttable 

presumption adopted in Order No. 697 for energy and capacity to include Energy 

Imbalance and Generator Imbalance provides adequate protection that market-based rates 

charged by public utilities will be just and reasonable and not unduly discriminatory or 

preferential. The Commission notes that this proposal would not constitute a revision to 

the Avista policy. Rather, this proposal merely finds that the existing market power 

screens can be applied to analysis of market power for Energy Imbalance and Generator 

Imbalance. As a result, sellers who pass the existing market power screens would not be 

subject to the sales restrictions otherwise required under the Avista policy. The 

Commission seeks comment on this proposal, including the proposed revisions to part 

35.37(c)(1) of our regulations, and its application to Energy Imbalance and Generator 

Imbalance services. Comments may address, among other things, any unique technical 

requirements or limitations that might apply to the provision of the ancillary imbalance 

services, and the Commission’s proposal to extend the rebuttable presumption to 

imbalance services.

21. There appear to be significant technical requirements or limitations that apply to the 

provision of ancillary services other than Energy Imbalance and Generator Imbalance such 

that the existing market-based rate screen may not be adequate to capture the potential 

horizontal market power of sellers of these other ancillary services. Technical 

considerations may limit the units capable of providing Reactive Supply and Voltage 

Control, Regulation and Frequency Response, Operating Reserve-Spinning, and Operating 

Reserve-Supplemental services as compared to the broader set of units capable of 

providing energy or capacity potentially requiring the identification of a different 
Docket Nos. RM11-24-000 and AD10-13-000 - 18 -

geographic market than the default geographic market used to conduct market power 

analyses for sales of energy and capacity and a change to the assumptions used to identify 

potential competing resources within that market. For example, the size of the relevant 

geographic market for a particular ancillary service may be subject to change based on 

system conditions and the need to meet applicable reliability criteria. The balancing 

authority may at times be able to procure ancillary services on a system-wide basis, 

whereas at other times factors may require the balancing authority to procure ancillary 

services on a zonal or even more location-specific basis. Further, not every facility that 

has the capability to provide energy will have the capability to provide every ancillary 

service. Also, the procurement may involve commercially sensitive internal decisionmaking that determines what proportion of a unit’s total capability will be dedicated to a 

particular ancillary service instead of energy and capacity.

22. With regard to Operating Reserve-Spinning and Operating Reserve-Supplemental, 

the Commission recognizes that resources used to provide these services are maintained to 

convert to energy if needed, as with imbalance services. However, minimum ramp rate 

requirements and stringent minimum start-up rates for off-line resources used for 

supplemental reserves apply to the provision of Operating Reserve-Spinning and 

Operating Reserve-Supplemental. For on-line resources, not all types of units may be 

capable of extended periods of operation below their fully loaded set point, or such 

operation may be prohibitively uneconomic. 

23. With regard to Reactive Supply and Voltage Control, technical and geographic 

considerations generally limit the units capable of providing this ancillary service as 

compared with the broader set of units capable of providing energy or capacity. In order 
Docket Nos. RM11-24-000 and AD10-13-000 - 19 -

to provide Reactive Supply and Voltage Control service, conventional synchronous 

generators must be able to vary the voltage level of their electrical output. Not all 

synchronous generators may choose to operate in a way that provides Reactive Supply and 

Voltage Control service. Similarly, non-traditional asynchronous resources require some 

other power electronic controls in order to provide this ancillary service, and not all 

owners of asynchronous resources choose to install the needed controls. Further, nongeneration resources may be technically capable of providing this ancillary service with 

appropriate controls, but they may not all choose to install the needed controls. Finally, as 

recognized in numerous venues and proceedings including Order No. 888, losses of 

reactive power during transmission may be significantly greater than losses incurred in 

delivering real power, meaning that reactive power must often be supplied from local 

resources.

45 Therefore, the appropriate relevant geographic market for Reactive Supply

and Voltage Control service could be smaller than the default geographic market discussed 

above and even within that reduced geographic market, not all resources may be capable 

of competing to provide this particular ancillary service. Moreover, conventional 

resources generally require Automatic Generation Control (AGC) equipment in order to 

provide Regulation and Frequency Response service, while non-traditional resources 

require power electronic controls that perform like AGC. Not all units have AGC or 

 45 FERC, Principles for Efficient and Reliable Reactive Power Supply and 

Consumption, Docket No. AD05-1-000, at 18 (2005), available at

http://www.ferc.gov/EventCalendar/Files/20050310144430-02-04-05-reactive-power.pdf.

(“Reactive power is difficult to transport. At high loadings, relative losses of reactive 

power on transmission lines are often significantly greater than relative real power losses . 

. . Losses in transmission lead to the expression that reactive power does not travel well.”).
Docket Nos. RM11-24-000 and AD10-13-000 - 20 -

power electronic controls that perform like AGC. Therefore, a different set of competing 

resources might need to be identified within the default geographic market for Regulation 

and Frequency Response service. 

24. The Commission seeks comments on whether the technical requirements for 

Operating Reserve-Spinning, Operating Reserve-Supplemental, Reactive Supply and 

Voltage Control, and Regulation and Frequency Response would necessitate a market 

power analysis based on a different geographic market or different set of resources as 

compared to those analyzed to determine market power for sales of energy and capacity. 

If so, we seek comment on how the relevant geographic market can be identified and how 

potentially competing resources with the needed characteristics can be identified within 

the relevant geographic market. Finally, we seek comment on whether the limited 

reporting requirement and optional market power screen, discussed further below, could be 

applicable for assessing the market power of potential sellers of these ancillary services.

b. Optional Market Power Screen

25. Several commenters to the NOI support the idea of developing alternative analyses 

for measuring market power for ancillary services,

46 while others propose that new 

reporting requirements be imposed to facilitate sellers’ ability to perform market power 

analyses for ancillary services markets.

47 Upon review of these comments, the 

Commission proposes a limited new reporting requirement that would provide potential 

 46 See, e.g., California PUC Comments at 5.

47 See, e.g., NGSA comments at 5 and EPSA comments at 3-4.
Docket Nos. RM11-24-000 and AD10-13-000 - 21 -

sellers of ancillary services48 with the information needed to develop market power 

analyses using an optional market power screen solely applicable to ancillary services. 

Specifically, the Commission proposes to require each public utility transmission provider

to publicly post on its OASIS information as to the aggregate amount (MW or MVAR, as 

applicable) of each ancillary service that it has historically required, including any 

geographic limitations it may face in meeting such ancillary service requirements.

49 For 

example, a hypothetical transmission provider may report that it has historically 

maintained 100 MW of Regulation and Frequency Response reserves for its balancing area 

and 100 MVAR of Reactive Supply and Voltage Control in each of two submarkets within 

its balancing authority area. 

26. The optional market power screen for an ancillary service would then compare the 

amount of capacity in MWs (or, as applicable, MVARs) that a potential seller can dedicate

to providing the ancillary service in the relevant geographic market with the buyer’s 

 48 The Commission envisions this optional screen being available as a voluntary 

alternative to the type of market power analyses described in Ocean Vista. The 

Commission also envisions permitting this optional screen to be used solely in connection 

with sales of Operating Reserve-Spinning, Operating Reserve-Supplemental, Reactive 

Supply and Voltage Control, and Regulation and Frequency Response services. Further, if 

our earlier proposal regarding application of the existing screens to Energy and Generator 

Imbalance services is not ultimately finalized, then we would envision permitting the 

application of this optional screen to those ancillary services as well. 

49 This requirement would parallel the existing requirement for a seller that owns, 

operates or controls transmission to conduct simultaneous transmission import capability 

studies for its home control area and each of its directly-interconnected first-tier control 

areas in order to facilitate market power analyses by all sellers in the relevant market. 

Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 346. The Commission’s existing 

requirements and policies with regard to submission of historical data would apply. 

Therefore, any concerns as to possible manipulation of this data should be ameliorated.
Docket Nos. RM11-24-000 and AD10-13-000 - 22 -

reported aggregate requirement for that ancillary service, taking into account any reported 

historical locational requirements (e.g., locational requirements due to such things as 

binding transmission constraints or the geographic limitations of Reactive Supply). Using 

this optional market power screen, sellers whose available capacity is no more than 20 

percent of the relevant reported aggregate requirement for an ancillary service would then 

receive a rebuttable presumption that they lack horizontal market power for the ancillary 

service in question. 

27. The Commission recognizes that this approach would be an alternative to the 

Commission’s historical approach to conducting market power analyses, though we 

believe it is consistent with the principles by which we developed our market power 

analyses. Moreover, this approach would be limited solely to market power analyses of 

ancillary services and would be permitted because of the lack of publicly-available 

information on the potential supply of various ancillary services in a given geographic 

market. In Ocean Vista the Commission explained that as a general matter, a study of 

ancillary service markets should address the nature and characteristics of each ancillary 

service, as well as the nature and characteristics of generators capable of supplying each 

service, and the study should develop market shares for each service.50 Of particular 

relevance here, the Commission stated that the market power analysis for ancillary 

services markets should identify the relevant geographic market, which could include all 

potential sellers of the product from whom the buyer could obtain the service, taking into 

 50 Id. P 1048.
Docket Nos. RM11-24-000 and AD10-13-000 - 23 -

account relevant factors which may include the other sellers’ locations, the physical 

capability of the delivery system and the cost of such delivery, and important technical 

characteristics of the sellers facilities.51

28. The proposed approach discussed above is consistent with these principles. 

Identification of the aggregate requirement for each ancillary service within the balancing 

authority area serves as a proxy for the identification of the amount and location of 

resources that may be technically capable of providing the requisite service in the relevant 

geographic market, without requiring resource-specific information for resources currently 

providing the service. The Commission has allowed use of proxies for various inputs to 

the indicative screens to simplify or streamline the analyses,

52 and in particular has stated 

that a seller, where appropriate, can make certain simplifying assumptions, such as 

performing the indicative screens assuming that the relevant market has no import 

capability (this was modified in later orders to mean no competing imports) or treating the 

host balancing authority area utility as the only other competitor.53 Essentially, the 

proposed proxy would treat the resources used historically by the host balancing authority 

 51 Id.

52 For example, the Commission has allowed wind generating facilities that lack 

five years of operational data to use a five-year average regional wind capacity factor 

based on data reported by the Energy Information Administration to de-rate their capacity. 

See Golden Spread Electric Cooperative, Inc., 138 FERC ¶ 61,208 (2012). Additionally, 

in Order No. 697, the Commission stated that it will allow the capacity of energy-limited 

facilities to be set equal to their five-year average historical capacity factor. Order No. 

697, FERC Stats. & Regs. ¶ 31,252 at P 344. The Commission also stated that it is willing 

to consider proxy amounts for simultaneous transmission import limits. Id. P 381. 

53 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 321.
Docket Nos. RM11-24-000 and AD10-13-000 - 24 -

area utility as the only other competing resources for purposes of market share analysis. 

This proxy would take into account the nature and characteristics of each ancillary service, 

as well as the nature and characteristics of resources capable of supplying each service and 

any limitations such as deliverability that have historically affected designation of 

resources to provide the ancillary service. The proposed approach would allow potential 

third party sellers to compare their ancillary service capacity to the capacity that has 

historically been needed to provide the service as shown by the relevant transmission 

provider’s OASIS posting of ancillary service requirements, and calculate a market share 

on that basis. 

29. The Commission preliminarily concludes that this approach will foster transparency 

and competition in the provision of ancillary services by providing information for 

ancillary service sellers to perform the market power analyses required by the 

Commission’s rules while continuing to provide protection for customers from the 

potential exercise of market power. As with the expansion of the rebuttable presumption 

for energy and capacity to include Energy Imbalance and Generator Imbalance proposed 

above, the optional power market screen for ancillary services proposed here would not 

constitute a revision to the Avista policy. Rather, it merely would provide another means 

of demonstrating a lack of market power in sales of ancillary services. As a result, sellers 

who pass this optional market power screen would not be subject to the sales restrictions 

otherwise required under the Avista policy.

30. The Commission seeks comment on whether the proposed limited OASIS reporting 

requirement combined with the opportunity to use an optional market power screen for 

ancillary services, as described above and in proposed new parts 37.6(k) and 35.37(c)(5) 
Docket Nos. RM11-24-000 and AD10-13-000 - 25 -

respectively of our regulations, will provide adequate protection that market-based rates 

charged by public utilities will be just and reasonable and not unduly discriminatory or 

preferential. The Commission also requests that commenters address the use of the 

optional screen for Energy and Generator Imbalance ancillary services given the 

Commission’s proposal above that sellers passing existing market-based rate analyses in a 

given geographic market should be granted a rebuttable presumption that they lack 

horizontal market power for sales of Energy Imbalance and Generator Imbalance ancillary 

services in that market. Additionally, the Commission requests comments on the 

appropriate level of detail to include in the proposed reporting requirement. The 

Commission is aware that balancing areas determine reserve requirements in different 

ways; for example, some may have static reserve requirements updated once a year, while 

others specify reserve requirements as a percentage of load, meaning that their reserve 

amounts can change throughout a year. The Commission does not at this time intend to 

change how balancing areas determine their reserve amounts. Rather, we wish the 

proposed OASIS reporting requirement to adequately capture whatever method the 

balancing area employs and be detailed enough to support the proposed optional market 

power screen. For example, if ancillary service reserve requirements change periodically 

throughout a year, should the associated OASIS posting show the different amounts of 

reserve procurement with their associated time periods or should the OASIS posting show 

a single average reserve procurement amount for the year? The Commission also asks for 

comments on whether the optional market power screen should only be implemented on 

an experimental basis until the Commission has more experience with the evolution of 

ancillary service markets and in reviewing the quality of optional market power screens.
Docket Nos. RM11-24-000 and AD10-13-000 - 26 -

2. Alternative Cost-Based Mitigation

31. The NOI also sought comment on alternative mitigation measures to the prohibition

adopted in Avista with regard to sales to a public utility that is purchasing ancillary 

services to satisfy its own OATT requirements to offer ancillary services to its own 

customers. In particular, the Commission sought comment on the possibility of relying on 

an explicit price cap based on the purchasing utility’s cost-based OATT ancillary service 

rates or the use of competitive solicitations. Based on a review of the resulting comments, 

the Commission seeks further comment regarding whether the specific alternative costbased mitigation measures described below that would allow third-party sales to a public 

utility without showing a lack of market power are adequate to ensure that rates charged 

by third parties for Regulation and Frequency Response, Operating Reserve-Spinning, or 

Operating Reserve-Supplemental service will be just and reasonable and not unduly 

discriminatory or preferential. In addition, while the Avista policy did not apply to

Reactive Supply and Voltage Control service, the Commission seeks comment on whether 

third-party sales of Reactive Supply and Voltage Control service to a public utility to 

satisfy its own OATT obligations should be permitted under one of the price cap options 

discussed below.

32. Specifically, the Commission proposes to permit sellers unable or unwilling to 

perform the market power study for ancillary services to propose price caps at or below 

which sales of Regulation and Frequency Response, Reactive Supply and Voltage Control,

Operating Reserve-Spinning, or Operating Reserve-Supplemental service would be 

allowed where the purchasing entity is a public utility purchasing ancillary services to 

satisfy its own OATT requirements to offer ancillary services to its own customers. Such 
Docket Nos. RM11-24-000 and AD10-13-000 - 27 -

a price cap would be based on one of the two possible OATT ancillary service rate caps

discussed below and, as in Avista, we propose that sales under these price caps would only 

be permitted in geographic markets where the seller has been granted market-based rate 

authority for sales of energy and capacity. Alternatively, a seller unable to perform a 

market power study for ancillary services could rely on competitive solicitations meeting 

certain minimum requirements in order to make sales in geographic markets where the 

seller has been granted market-based rate authority for sales of energy and capacity. 

a. Use of Price Caps

33. As noted above, the Commission in the NOI explored the idea of using price caps 

based on the purchasing utility’s OATT rates to serve as an alternative mitigation to the 

Avista policy. Use of price caps or other proxies is not unprecedented. For example, the 

Commission has long permitted cost-of-service sellers to propose cost-justified ceiling 

rates to allow the seller to respond quickly to market opportunities by discounting below 

the approved ceiling.54 In many respects the cost-based ceiling rate umbrella tariffs of 

decades past may have helped begin the development of bilateral markets for energy and 

capacity, and we believe the development of bilateral markets for ancillary services today 

 54 See, e.g., Central Maine Power Company, 56 FERC ¶ 61,200, at 61,818-19 

(1991) (“We are aware of the argument that, due to the need to respond quickly to market 

changes and opportunities for coordination, in some cases transactions must begin before 

the utility has a chance to file the rate reflecting the transaction with the Commission. 

While this argument has some merit, we note that many utilities have managed to avoid 

this problem by having tariffs on file that permit transactions to be negotiated subject to a 

cap of 100-percent contribution to fixed costs.” (emphasis added)). 
Docket Nos. RM11-24-000 and AD10-13-000 - 28 -

may similarly benefit from the availability of appropriate price cap options. Below we 

propose two options for comment.

34. First, third parties would be permitted to sell to a public utility buyer at rates not to 

exceed the buying public utility transmission provider’s existing OATT rate for the same 

ancillary service. The Commission anticipates that this option should be relatively noncontroversial to implement as the buyer’s OATT ancillary service rates will have already 

been found to be just and reasonable. However, we recognize that in some situations this 

type of price cap may do little to signal a buyer’s interest in the procurement of ancillary 

services or reflect the actual practices in a region, which may include pooling or sharing of 

reserves. Rather, a policy that relies on the rate of a single buyer may serve as a 

disincentive to the entry of additional resources to provide ancillary services and 

ultimately undermine the goal we are trying to achieve of providing sellers some 

flexibility while ensuring just and reasonable rates. The Commission also appreciates that 

an individual buyer’s OATT ancillary service rates may be higher or lower than the cost of 

new entry and that they do not necessarily signal whether investment is needed to provide 

the service. 

35. Notwithstanding these potential limitations of relying on a cap at the buying public 

utility transmission provider’s OATT ancillary service rate, the Commission believes that 

such a cap could provide a means of mitigating the potential market power of sellers 

unable to perform a market power analysis. Furthermore, a price cap based on the buyer’s 

OATT ancillary service rate may best match the geographic limitations of an ancillary 

service like Reactive Supply and Voltage Control, and may provide the simplest route to 

expanded supply at just and reasonable rates for service areas that require more Reactive 
Docket Nos. RM11-24-000 and AD10-13-000 - 29 -

Supply and Voltage Control. The Commission seeks comment on whether this cost-based 

cap would provide an effective alternative to imposition of the Avista restriction for 

mitigating potential market power. The Commission also seeks comment on whether this 

type of cap would induce the provision of ancillary services, particularly from parties who 

believe that this cap would be beneficial to their efforts to buy or sell specific ancillary 

services, such as Reactive Supply and Voltage Control. We also seek comment on 

whether the Commission should require additional transparency provisions to accompany 

such a cap beyond electric quarterly reports. These provisions may include the 

transmission provider posting its need for ancillary services and any seller responses.

36. Under the second option, third parties could propose to sell a given ancillary service 

to a public utility buyer at rates not to exceed the highest public utility transmission 

provider OATT rate within the relevant geographic market for physical trading of the 

ancillary service in question. Under this type of regional price cap, the seller (or group of

sellers) would be required to file with the Commission a proposal that defines the scope of 

a contiguous geographic region that both encompasses the service territory(ies) of the 

public utility transmission provider whose OATT ancillary service rate will form the basis 

for the price cap, and within which trading of the ancillary service in question is physically 

possible. Using the highest OATT ancillary service rate as a price cap for a predefined 

market area with the characteristics above may address some of the potential limitations of 

a price cap based on an individual public utility transmission provider OATT identified 

above. Additionally, it may be a more reasonable approximation of the cost of new entry 

within a market where physical trading of the ancillary service in question is possible. 
Docket Nos. RM11-24-000 and AD10-13-000 - 30 -

37. Such a regional price cap proposal could be proposed for any contiguous trading 

area within which the filer or filers propose to make physical trades of ancillary services. 

The Commission anticipates that this trading area often may include the seller’s home 

balancing authority area plus first-tier balancing authority areas and possibly additional 

areas where transmission capacity is available. However, the Commission is concerned

that sellers could seek to define regions that are unrealistically broad in order to access a 

high OATT ancillary service rate from outside their region that may not be appropriate 

elsewhere. To prevent this type of distortion, the Commission proposes to require price 

cap sellers to show that the ancillary services in question can be physically traded 

throughout the region they propose for a given ancillary service price cap. Such a showing 

would need to take into account the technical characteristics of the ancillary service in 

question in order to demonstrate the physical ability to trade in the proposed market area. 

For example, because of their different characteristics, a contiguous geographic region 

within which it is physically possible to trade Operating Reserve-Spinning is likely to be 

much greater than any contiguous geographic region within which it is physically possible 

to trade Reactive Supply and Voltage Control. We seek comment on the types of 

information available to make such a showing. 

38. Also, because different sellers proposing to sell the same ancillary service could 

conceivably propose different but overlapping trading regions, which might result in 

multiple regional price caps applying to sales in the overlapping areas, the Commission 

seeks comment on whether this type of overlap should be permitted. If not, the 

Commission seeks comment on ways to prevent such overlap in the definition of trading 

regions. In a similar vein, the Commission also recognizes the possibility that some sellers 
Docket Nos. RM11-24-000 and AD10-13-000 - 31 -

may propose a regional price cap for a given trading area, while other sellers in the same 

trading area may propose to sell to specific buying public utilities under the other price cap

option discussed above; a price cap set at the buying public utility’s relevant OATT 

ancillary service rate. The Commission seeks comment on whether this type of overlap 

should be permitted and, if not, on ways it could be prevented. 

39. As discussed earlier, the Commission recognizes that the single-public utility price 

cap option may best match the geographic limitations associated with Reactive Supply and 

Voltage Control service. Should the Commission, as a result, exclude Reactive Supply 

and Voltage Control from the list of ancillary services eligible for a regional price cap 

proposal, meaning that Reactive Supply and Voltage Control could only be sold under a 

price cap based on the buying public utility’s OATT rate for Reactive Supply and Voltage 

Control?

40. The Commission proposes to amend its regulations at part 35.38 to provide that 

either of the OATT-based price caps described above can be proposed as mitigation of 

potential horizontal market power in ancillary services for those sellers who fail or forego 

relevant, properly defined market power screens for the ancillary service in question. The 

Commission preliminarily concludes that either cap could serve as an alternative method 

of ensuring just and reasonable rates for ancillary services that would, unlike the Avista 

mitigation scheme, permit willing buyers and sellers of ancillary services to transact, and 

thus provide a means of increasing the supply of needed ancillary services in a timely and 

cost-effective manner. The Commission seeks comment on its proposal, including 

whether these price caps will provide an effective mitigation measure as an alternative to 
Docket Nos. RM11-24-000 and AD10-13-000 - 32 -

imposition of the Avista restriction, and how the Commission should address the other 

questions described above. 

b. Competitive Solicitations

41. The NOI also sought comment regarding whether transmission providers’ use of 

open and transparent competitive solicitations could facilitate the provision of ancillary 

services and ensure just and reasonable rates. The Commission sought comment regarding 

whether a standardized competitive solicitation process could be developed for particular 

regions or markets.

42. While commenters are generally supportive of the use of competitive solicitations, 

some contend that competitive solicitations should not be the only option for mitigating 

market power concerns because past solicitations for ancillary services have not always 

produced enough interest to ensure a competitive outcome, and this may continue to be the 

case for some time to come.

55 WSPP also argues that competitive solicitations are 

probably impractical for short-notice transactions that would commence within a month or 

less.56 However, others appear to suggest that the Commission mandate that all ancillary 

services be procured through competitive solicitations.57

43. The comments on this issue indicate that competitive solicitations may not be 

appropriate for all transactions and may not be sufficient to mitigate potential market 

 55 Bonneville Comments at 8-9.

56 WSPP Comments at 21-22.

57 ESA Comments at 11-12, PPL Companies Comments at 9, IID Comments at 15, 

and CAREBS Comments at 6.
Docket Nos. RM11-24-000 and AD10-13-000 - 33 -

power in the sale of ancillary services in every circumstance. However, this does not 

mean that competitive solicitations should not be available as an option for mitigating 

potential market power concerns. The Commission proposes to allow applicants to engage 

in sales to a public utility that is purchasing ancillary services to satisfy its OATT 

requirements to offer ancillary services to its own customers where the sale is made 

pursuant to a competitive solicitation that meets the following requirements.

44. Specifically, the Commission has stated that the following four guidelines help

determine if a competitive solicitation process satisfies the principle that no affiliate

should receive undue preference during any stage of a request for proposals: (1) 

transparency: the competitive solicitation process should be open and fair; (2) definition: 

the product or products sought through the competitive solicitation should be precisely 

defined; (3) evaluation: evaluation criteria should be standardized and applied equally to 

all bids and bidders; and (4) oversight: an independent third-party should design the 

solicitation, administer bidding, and evaluate bids prior to the company’s selection.58 

45. While the Commission originally issued these guidelines for the purpose of 

preventing undue affiliate preference, we believe they are also applicable in the context of 

using competitive solicitations to help mitigate the potential exercise of horizontal market 

power by sellers of ancillary services. However, even if a solicitation process meets all of 

these guidelines, it may still fail to attract sufficient numbers of sellers to properly 

discipline resulting market prices. Accordingly, for purposes of a mitigation proposal 

 58 See, e.g., Allegheny Energy Supply Co. LLC, 108 FERC ¶ 61,082 (2004).
Docket Nos. RM11-24-000 and AD10-13-000 - 34 -

applicable to market-based sales of ancillary services, the Commission proposes to require 

entities filing such a proposal to demonstrate to the Commission that the solicitation 

attracted sufficient seller interest to properly discipline market prices. This showing 

would be required in addition to the four criteria listed above. The Commission believes 

that all of these requirements in combination will protect against horizontal market power 

and thereby ensure just and reasonable rates. We seek comment on this proposal and 

encourage commenters to develop ideas for ways in which competitive solicitations can be 

structured to accommodate near-term transactions.

46. Consistent with the discussion above, the Commission proposes to amend section 

35.38 of its regulations to provide the opportunity for public utilities seeking waiver of the 

Avista restriction to rely on competitive solicitations meeting the Commission’s 

requirements for transparency, definition, evaluation, oversight, and adequate seller 

interest.

B. Resource Speed and Accuracy in Determination of Regulation and 

Frequency Response Reserve Requirements

47. In addition to exploring potential changes to the Commission’s requirements for 

market-based rate authority discussed above, the NOI also sought comment on whether the 

various cost-based compensation methods for Regulation and Frequency Response service 

that exist in regions outside of the current organized markets could be adjusted to address 

the issues identified in the proceeding that led to the issuance of Order No. 755.

59 In that 

 59 Order No. 755, FERC Stats. & Regs. ¶ 31,324 at P 68 (“faster-responding 

resources have the potential to lower frequency regulation capacity requirements, thereby 

improving market efficiencies”).
Docket Nos. RM11-24-000 and AD10-13-000 - 35 -

proceeding, the Commission required changes to compensation mechanisms for 

Regulation and Frequency Response service in the RTO and ISO markets to ensure that all 

resources providing service are compensated in a just and reasonable and not unduly 

discriminatory manner. While acknowledging that the specific reforms ultimately adopted 

in Order No. 755 would not apply outside of RTOs and ISOs, the NOI questioned whether 

the underlying goal of better valuing the benefits of faster, more accurate provision of 

Regulation and Frequency Response service could be achievable in other ways outside of 

RTOs and ISOs. 

48. Specifically, the NOI sought comment on: 1) how a cost-based cap for Regulation 

and Frequency Response service in the WSPP Agreement60 could be structured to reflect 

 60 The WSPP Agreement was initially accepted by the Commission on a nonexperimental basis in 1991, and provided for flexible pricing for coordination sales and 

transmission services. See Western Sys. Power Pool, 55 FERC ¶ 61,099, order on reh'g, 

55 FERC ¶ 61,495 (1991), aff'd in relevant part and remanded in part sub nom.

Environmental Action and Consumer Federation of America v. FERC, 996 F.2d 401, 302

U.S. App. D.C. 135 (D.C. Cir. 1992), order on remand, 66 FERC ¶ 61,201 (1994). Prior 

to 1991, the WSPP Agreement was used for three years on an experimental basis. See 

Pacific Gas and Electric Co., 50 FERC ¶ 61,339 (1990) (extending the initial two-year 

period of the WSPP Agreement for an additional year). The WSPP Agreement as it exists 

today permits sellers of electric energy to charge either an uncapped market-based rate (for 

public utility sellers, they must have obtained separate market-based rate authorization 

from the Commission to do this), or an "up to" cost-based ceiling rate. For sellers without 

market-based rate authority, the cost-based rate under the WSPP Agreement consists of an 

individual seller’s forecasted incremental cost plus an “up to” demand charge based on the 

average fixed costs of a subset of the original parties to the WSPP Agreement, so long as 

the seller can justify the use of this charge based on its own fixed costs. Otherwise, the 

seller must file a separate stand-alone rate schedule that is cost-justified based on the 

individual seller’s own costs. See Western Sys. Power Pool, 122 FERC ¶ 61,139 (2008) 

(finding that it is not just and reasonable to allow a seller to use the WSPP-wide “up to” 

demand charge as a ceiling rate in markets where the seller does not have market-based 

rate authority unless such a seller can cost-justify the use of the “up to” demand charge 

based on its own fixed costs). Currently, there are over 300 parties to the WSPP 

(continued...)
Docket Nos. RM11-24-000 and AD10-13-000 - 36 -

an individual resource’s performance; 2) whether transmission customers that self-supply 

Regulation and Frequency Response service could be permitted to determine the amount 

of capacity they procure based on the third-party resource’s performance capability; and 3) 

any other way to extend the goals of the Frequency Regulation Compensation NOPR,

61

which ultimately resulted in Order No. 755, outside of the ISOs and RTOs.

49. Most of the more concrete NOI comments on this issue focus on the second 

question above: whether transmission customers that self-supply Regulation and 

Frequency Response service could be permitted to determine the amount of capacity they 

procure based on the third-party resource’s performance capability.62 Some commenters 

suggest that customers choosing to self-supply Regulation and Frequency Response 

service from faster-acting resources should be allowed to self-supply a lower volume of 

regulation capacity.63 Powerex suggests that each balancing authority be required to 

maintain well-defined criteria under which a transmission customer self-providing 

 

Agreement located throughout the United States and Canada, including private, public and 

governmental entities, financial institutions and aggregators, and wholesale and retail 

customers. 

61 Frequency Regulation Compensation in the Organized Wholesale Power 

Markets, FERC Stats. & Regs. ¶ 32,672 (2011) (Frequency Regulation Compensation 

NOPR). Order No. 755 had not yet issued at the time of the NOI in this proceeding.

62 See, e.g., Bonneville Comments at 9-10, California Storage Alliance Comments 

at 14-19, ESA Comments at 27-28, Powerex Comments, Appendix A at 8, and A123 

Comments at 2-4. Other comments included WSPP’s suggestion that a rate cap proposal 

could use the two-part rate design described in the Frequency Regulation NOPR, but 

WSPP does not provide any details regarding how such a rate design could be structured. 

WSPP Comments at 26-27.

63 California Storage Alliance Comments at 14-17; ESA Comments at 27-28.
Docket Nos. RM11-24-000 and AD10-13-000 - 37 -

ancillary service reserves can adjust the level of reserves based on the ramping capability 

of the resources it uses.64 Bonneville states that, in such circumstances, the balancing 

authority should make the determination as to the appropriate level of capacity 

procurement, not the customer itself.65 

50. Under the existing requirements of the pro forma OATT, each public utility 

transmission provider is required to provide its transmission customers with the option of 

self-supplying certain ancillary services, including Regulation and Frequency Response 

service.66 This self-supply option has been clear since Order No. 888 and, therefore, 

public utility transmission providers must be prepared to provide self-supply requirements 

on request from a transmission customer. However, the Commission to date has not 

addressed the extent to which such requirements should reflect the characteristics of 

particular resources being used to provide Regulation and Frequency Response service.

51. The Commission proposes to require that each public utility transmission provider 

submit provisions for inclusion in its OATT that take into account the speed and accuracy 

of regulation resources in determining its Regulation and Frequency Response reserve 

requirements.67 These provisions must include a description of how the public utility 

 64 Powerex Comments, Appendix A at 8.

65 Bonneville Comments at 10.

66 See, e.g., Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,716; pro forma 

OATT, Original Sheet Nos. 20-21 and Schedule 3, Original Sheet No. 113. 

67 The Commission acknowledges that each balancing authority is responsible for 

determining its reserve requirements in order to comply with relevant NERC reliability 

standards, and that sometimes an individual OATT transmission provider may be its own 

(continued...)
Docket Nos. RM11-24-000 and AD10-13-000 - 38 -

transmission provider would make adjustments to the capacity requirement when a 

customer opts to self-supply its requirements, including through purchases from thirdparties, using resources with speed and accuracy characteristics that differ from the set of 

resources otherwise being used for Regulation and Frequency Response. This description 

could include the set of resources the public utility transmission provider uses to provide 

Regulation and Frequency Response service, indicating the capacity typically set aside 

from each resource and the ramp rate associated with each resource. The description 

needs to provide enough detail to allow an entity wishing to self-supply to compare the 

resources it proposed to use to the resources the public utility transmission provider is 

using to provide Regulation and Frequency Response service. Presumably, this 

adjustment could be in either direction: down if the customer self-supplies with faster or 

more accurate resources or up if it uses slower or less accurate resources.

52. The Commission preliminarily finds that accounting for speed and accuracy in a 

public utility transmission provider’s determination of Regulation and Frequency 

Response reserve requirements is necessary to address the potential for undue 

discrimination against customers choosing to self-supply their Regulation and Frequency 

 

balancing authority and other times it may be part of a larger balancing authority. The 

Commission also notes that a new standard, BAL-003-1(Frequency Response and 

Frequency Bias Setting), is currently under development by NERC stakeholders and may 

assign a frequency response obligation to each balancing authority or reserve sharing 

group and require each balancing authority or reserve sharing group to use an appropriate 

frequency bias setting in its ACE equation and to achieve an adequate annual frequency 

response measure. While frequency response is distinguished from frequency regulation 

by the manner in which it is controlled (see, e.g., Order No. 755, FERC Stats. & Regs. 

¶ 31,324 at n.5), this standard may also be relevant to a balancing authority’s 

determination of its overall reserve requirements. 
Docket Nos. RM11-24-000 and AD10-13-000 - 39 -

Response needs, including through purchases from third-parties. The Commission is 

concerned that a public utility transmission provider could engage in undue discrimination 

by requiring such customers to procure a different amount of regulation reserves than the 

particular speed and accuracy characteristics of the resources in question justify. 

Accordingly, the Commission proposes to amend its regulations at part 35.28 to require 

that public utility transmission providers amend their OATTs at Schedule 3 (Regulation 

and Frequency Response Service) to explain how they will take into account the speed and 

accuracy of regulation resources in determining Regulation and Frequency Response 

reserve requirements. The Commission acknowledges that each public utility transmission 

provider has unique needs related to Regulation and Frequency Response reserve 

requirements and, accordingly, may account for speed and accuracy in different ways. 

Therefore, the Commission does not at this time seek to mandate a particular methodology 

but instead expects that it would evaluate each proposed determination relevant to 

Regulation and Frequency Response reserve requirements on a case-specific basis. 

53. The Commission seeks comment on this proposal, including comment on how 

speed and accuracy can be taken into account in the determination of Regulation and 

Frequency Response reserve requirements, and the Commission’s preliminary conclusion

that requiring transparency in the determination of Regulation and Frequency Response 

reserve requirements will help prevent undue discrimination in the form of public utility 

transmission providers requiring self-supplying customers to procure a different amount of 

regulation reserves than the particular speed and accuracy characteristics of the resources 

in question justify. 
Docket Nos. RM11-24-000 and AD10-13-000 - 40 -

54. Further, in consideration of the comments regarding the ability of a customer to 

self-supply ancillary services, we take this opportunity to remind public utility 

transmission providers that they are already required to post on their public websites all 

rules, standards, and practices, to the extent they exist, that relate to transmission service. 

This includes the provision of ancillary services which are necessary to the provision of 

transmission service. As such, the obligation is clear and we see no need at this time to 

propose reforms.68 

C. Accounting and Reporting for Energy Storage Operations 

55. Finally, the NOI also asked about the Commission’s accounting and reporting 

requirements for energy storage operations. Comments were sought on what changes, if 

any, should be made to the Commission’s accounting and reporting regulations to provide 

for energy storage services, assets and operations. Comments were received from public 

utilities, industry associations, government agencies, and others. As noted in the NOI, the 

accounting regulations currently found in the USofA and the related reporting 

requirements were developed to capture financial and operational information along 

traditional primary business functions – production, transmission, and distribution of 

electric energy.69 Further, as also noted, energy storage assets can have operating 

characteristics of each of these functions and some may be capable of performing multiple 

 68 139 FERC ¶ 61,246.

69 NOI, 135 FERC ¶ 61,240 at P 25.
Docket Nos. RM11-24-000 and AD10-13-000 - 41 -

functions simultaneously.

70 Accordingly, entities using energy storage assets may seek 

multiple methods of cost recovery for their investments in and use of a single energy 

storage asset to provide various utility services.

71 

56. Numerous comments were received regarding the need for updating the USofA and 

Form Nos. 1 and 1-F for the accounting and reporting of public utilities. Most 

commenters are supportive of making amendments to accommodate energy storage 

transactions. However, some commenters indicate that the Commission’s current 

accounting and reporting requirements sufficiently accommodate these types of 

transactions.

57. In general, commenters that support amending the current accounting and reporting 

requirements indicate that the operating nature of energy storage assets is different from 

typical electric plant assets. These commenters indicate that energy storage assets can be 

used to serve multiple purposes – production, transmission, or distribution – whereas 

traditional electric plant assets only serve one purpose. Consequently, they explain that 

this difference in capabilities can mandate, in certain cases, that the energy storage assets 

be accounted for differently than traditional electric plant assets. These commenters 

indicate that changes to the accounting and reporting requirements are needed to address 

concerns about the potential for cross-subsidization and double or over-recovery of costs 

in instances where an energy storage asset is simultaneously included in cost-based and 

 70 Id.

71 Id.
Docket Nos. RM11-24-000 and AD10-13-000 - 42 -

market-based rates. Most of these commenters recommend specific accounting and 

reporting amendments that could assist with protecting against these concerns and certain 

other commenters in this group expressed that the concern existed but offered no 

recommendations. For example, Electricity Consumers did not propose specific 

accounting changes; however, it indicates that it supports accounting treatments that could 

enhance cost transparency to protect against double-recovery of costs.72

58. Several commenters recommend that the Commission create a new energy storage 

functional classification with associated plant and operation and maintenance (O&M) 

expense accounts for energy storage assets and operations. TAPS states that because the 

functional use of a given energy storage facility may change over time and may not fit 

neatly into any one existing functional category, and because energy storage facility costs 

may come to be recovered through storage-specific rate schedules, the only transparent 

and administratively efficient way to account for energy storage plant costs is by adding 

new accounts to the USofA.

73 TAPS contends that the overall objective of any changes 

should be to support either effective cost-based regulation of jurisdictional services 

provided using energy storage resources, or effective market power monitoring and

mitigation.

74 APPA agrees with TAPS’ comments.75

 72 Electricity Consumers Comments at 8.

73 TAPS Comments at 13.

74 Id. at 12.

75 APPA Comments at 7.
Docket Nos. RM11-24-000 and AD10-13-000 - 43 -

59. The Public Interest Organizations state that a separate asset class may prove the 

best way to provide full and comparable treatment for energy storage facilities.76 NGK/TI

argues that a new functional classification is needed because energy storage assets are 

functionally distinct from traditional production, transmission, and distribution assets and 

energy storage functions cross-cut these traditional functions.77

60. Other commenters recommend that the Commission create new plant and O&M 

expense accounts within the existing functional classifications of production, transmission, 

and distribution rather than creating a new functional classification specifically for energy 

storage. FirstEnergy states that new energy storage technologies may provide 

transmission, distribution, or production services, and the current USofA adequately 

provides for facilities and activities that provide these functions. However, FirstEnergy 

states that the USofA does not provide the necessary accounting transparency for new 

storage technologies. FirstEnergy recommends that the Commission establish new 

accounts within the currently established functions to provide additional accounting 

transparency and detail regarding the plant costs and O&M expenses of energy storage 

facilities that serve these functions.78 FirstEnergy states that the accounting should strive 

for transparency by identifying each type of asset with the primary function it serves and 

aligning the expenses associated with the asset with the revenues it provides. SDG&E 

 76 Public Interest Organizations Comments at 12.

77 NGK/TI Comments at 10.

78 FirstEnergy Comments at 5.
Docket Nos. RM11-24-000 and AD10-13-000 - 44 -

contends that energy storage assets should be classified in the existing classifications as 

production, transmission, or distribution as determined by the owner of the assets and 

consistent with the jurisdictional nature of the service that the energy storage device 

provides.79 

61. Commenters opposed to amending the current accounting and reporting 

requirements generally argue that the existing requirements adequately accommodate 

energy storage technologies. CAREBS asserts that the Commission’s goal should be to 

use, where possible, existing accounting methods rather than invent new ones. 

SolarReserve argues that because many sales of ancillary services would be made under 

sellers’ market-based rate authority, the sellers would have waivers of the accounting and 

reporting requirements at issue here.80 Thus, in SolarReserve’s opinion, there is no need 

to amend the Commission’s accounting and reporting requirements. 

62. California Storage Alliance and ESA indicate that if the Commission decides 

against creating new energy storage plant accounts and instead proposes to use existing 

plant accounts to account for energy storage resources, there would need to be changes to 

existing plant accounts to better capture energy storage plant costs. In this instance, 

California Storage Alliance and ESA recommend that the Commission revise the 

instructions of current plant accounts to explicitly include energy storage resources.81 

 79 SDG&E Comments at 4.

80 SolarReserve Comments at 5.

81 California Storage Alliance Comments at 29; and ESA Comments at 36.
Docket Nos. RM11-24-000 and AD10-13-000 - 45 -

63. Responding to concerns about the potential for cross-subsidization in instances 

where a energy storage resource simultaneously provides multiple services under costbased and market-based cost recovery mechanisms, EEI reasons that the Commission’s 

current policies can address concerns of cross-subsidization. EEI states that a 

jurisdictional entity should separately account for services sold under cost-based rates and 

those that are sold under market-based rates to prevent unfair market advantages through 

subsidization.82 Further, EEI states that if an energy storage device is providing a 

transmission service then it should be accounted for based on its primary use when it was 

initially placed in service.83 California PUC makes a similar argument indicating that the

energy storage device should be accounted for based on its intended use within a project.

64. EEI and other commenters also argue that energy storage technologies are in an 

early stage of the technology and that the Commission should wait before implementing 

new accounting or reporting requirements for energy storage assets. California PUC 

asserts that due to the complexity of the technologies and their multiple potential uses, to 

avoid disruption of the existing functional classification system the Commission should 

use a case-by-case exception approach to determine the appropriate classification.84

 82 EEI Comments at 10.

83 Id.

84 California PUC Comments at 7.
Docket Nos. RM11-24-000 and AD10-13-000 - 46 -

1. Proposed Accounting Requirements

65. While the Commission’s accounting and reporting requirements associated with the 

USofA do not dictate the ratemaking decisions of this Commission or State Commissions, 

these accounting and reporting requirements nevertheless support the rate oversight needs 

of both this Commission and State Commissions. Accordingly, the Commission strives to 

ensure that its accounting and reporting requirements keep pace with the evolution of the 

electric industry. As the industry has evolved, the Commission has relied on its 

accounting and reporting requirements applicable to existing public utilities85 (i.e., 

principally investor-owned utilities) to obtain information about an entity’s financial 

condition and results of operations. This information is important in developing and 

monitoring rates, making policy decisions, compliance and enforcement initiatives, and 

informing the Commission and the public about the activities of entities that are subject to 

these accounting and reporting requirements.86 

66. The Commission has required public utilities to continue to prepare their financial 

statements in accordance with the accounting requirements of the USofA, as it can 

accommodate most transactions and events affecting these entities. Under the 

Commission’s accounting and reporting requirements, public utilities must record and 

classify electric plant assets in the prescribed primary plant accounts based on the purpose 

 85 The term “public utility” means any person who owns or operates facilities

subject to the jurisdiction of the Commission under the Federal Power Act. 18 CFR Part

101 (2011) (Definition No. 29).

86 Applicants for market-based rate authority that do not sell under cost-based rates

frequently seek and typically are granted waiver of many or all of these requirements.
Docket Nos. RM11-24-000 and AD10-13-000 - 47 -

served or use of the asset to produce, transmit, or distribute electric energy. In addition, 

public utilities must also record and classify O&M expenses related to such plant assets 

based on the specific activity the efforts support. The electric plant assets and related 

O&M expenses must be reported in annual and quarterly Form Nos. 1, 1-F, and 3-Q 

reports that are maintained in accordance with the accounting requirements of the USofA. 

67. As stated in the NOI, the roles of traditional production, transmission, and 

distribution assets are generally well understood and each has established method(s) of 

accounting and reporting; however, the same is not necessarily true of energy storage 

assets which can operate in ways that resemble production, transmission, and/or

distribution.87 Moreover, it may be possible for some energy storage assets to provide 

some combination of production, transmission, and distribution services simultaneously. 

Accordingly, public utilities using energy storage assets may seek multiple methods of 

cost recovery for their investments in, and use of, the assets to provide various utility 

services.88 Consequently, due to the potential to use certain energy storage technologies to 

provide multiple services and the possibility that a public utility could simultaneously 

recover costs under both cost-based and market-based rates, the Commission sought 

comment in the NOI on whether current accounting and reporting requirements for 

activities and costs for the operation of energy storage resources provide sufficient 

transparency. 

 87 NOI, 135 FERC ¶ 61,240 at P 25. 

88 Id.
Docket Nos. RM11-24-000 and AD10-13-000 - 48 -

68. After analyzing all comments received and considering the Commission’s 

informational needs, the Commission has determined that the current accounting and 

reporting requirements do not provide sufficiently transparent information on the activities 

and costs of new energy storage operations. Consequently, the Commission proposes to 

amend the USofA and Form Nos. 1, 1-F, and 3-Q to provide financial and operational 

information on energy storage assets. 

69. The Commission proposes to add new electric plant and O&M expense accounts to 

record the installed cost and operating and maintenance cost of energy storage assets and a 

new account to record the cost of power purchased for use in energy storage operations. In 

addition, the Commission proposes to amend the Form Nos. 1, and 1-F to include the new 

accounts and amended schedules to report statistical and operational information on 

energy storage operations. Further, the Commission proposes to amend a schedule of the 

Form No. 3-Q to include the proposed new account to record the cost of power purchased 

for use in energy storage operations. The Commission seeks comment on these proposed 

amendments, including whether the proposed changes will provide sufficiently transparent 

information on the activities and costs of new energy storage operations. 

70. Numerous commenters responding to the NOI indicate that the Commission’s 

current accounting and reporting requirements for new energy storage assets are not 

sufficiently transparent. Many of these commenters suggest that the Commission address 

this matter by either creating new plant and O&M expense accounts to specifically account 

for energy storage assets and operations in the existing functional classifications of 

production, transmission, and distribution, or creating a new separate functional 

classification for energy storage operations and new associated energy storage plant and 
Docket Nos. RM11-24-000 and AD10-13-000 - 49 -

O&M expense accounts. While both options would satisfy the Commission’s and the

public’s need for detailed and transparent financial and operation information on public 

utilities’ use of energy storage resources to provide jurisdictional services, the latter option 

is unnecessary because the existing functional classifications can adequately support 

energy storage operations. Furthermore, creating a new functional classification does not 

provide additional benefits compared to creating new accounts within existing 

classifications. Our proposed amendments to the Form Nos. 1 and 1-F would require 

utilities with energy storage operations to report detailed financial and operation 

information on energy storage assets and activities in new schedules for all functions.

89

Thus, using existing functional classifications provides the same level of transparency as 

would creating a new functional class.

71. Moreover, the Commission understands that the energy storage industry continues

to evolve, and as some commenters observe, the use of energy storage resources in largescale public utility operations is at an early stage of development. However, commenters 

recommending that the Commission wait until the industry is more mature before 

imposing any accounting and reporting requirements for energy storage assets and 

operations disregard the current need for certainty in the accounting and reporting 

treatment for energy storage resources and operations. Uniform, transparent and 

consistent reporting of information on energy storage operations by public utilities is 

essential, especially by those seeking to recover costs of energy storage services in cost-

 89 See, discussion of proposed amendments to Form Nos. 1 and 1-F at PP 101-106.
Docket Nos. RM11-24-000 and AD10-13-000 - 50 -

based rates. This need for information is heightened by the chance that public utilities 

could seek to simultaneously recover service costs under cost-based and market-based rate 

mechanisms using a single energy storage asset.90 

72. Transparency improvements achieved through revisions to the existing accounting 

and reporting requirements will enhance the Commission’s and other form users’ ability to 

make a meaningful assessment of a utility’s cost of service and rates. Further, this will 

enable the Commission and others to better monitor for cross-subsidization. The 

overarching purpose of these proposed accounting and reporting amendments is to provide 

useful financial and operational information to regulatory agencies and other users of 

public utilities’ financial statements by establishing uniform accounting and reporting 

requirements for energy storage assets and operations. 

73. The Commission endeavors to achieve a balance between the benefits of revising 

its accounting and reporting regulations and the imposition of any additional burden on 

utilities. Information that would be reported for energy storage assets and operations

differs little from other data public utilities maintain under the USofA. If a utility owns 

and operates these energy storage assets, reporting information on them in the proposed 

accounts and FERC form schedules should not be burdensome. Requiring utilities to 

classify and account for energy storage assets and operations under existing functional 

classifications rather than a new one addresses the Commission’s and the public’s need for 

 90 The Commission has not to date received any proposals from public utilities that 

simultaneously seek to recover costs under cost-based and market-based rate mechanisms 

using a single energy storage asset, but the Commission remains open to innovative 

solutions and will evaluate proposals on a case-by-case basis.
Docket Nos. RM11-24-000 and AD10-13-000 - 51 -

detailed and transparent information and lessens the implementation burden on public 

utilities and licensees subject to Commission accounting and reporting requirements. 

74. SolarReserve argues that the accounting and reporting requirements should not be 

amended because many sales of ancillary services would be made under the sellers’ 

market-based rate authority. This argument is unconvincing. While public utilities using 

energy storage resources that are granted market-based rate authority by the Commission 

may seek waivers of the accounting and reporting requirements at issue here, there are 

instances when public utilities may not seek or fail to be granted waiver of the 

requirements. Additionally, previously granted waivers may be rescinded where a seller is 

found to have market power (or where the seller accepts a presumption of market power) 

and the seller proposes cost-based rate mitigation or the Commission imposes cost-based 

rate mitigation. Also, public utilities seeking to only recover storage costs under costbased rates will be subject to these accounting and reporting requirements. 

75. Furthermore, in instances where public utilities seek to simultaneously recover 

costs under cost-based and market-based rates, the Commission proposes that the entities 

be required to account for and report their operations in accordance with the Commission’s 

accounting and reporting requirements to facilitate development and monitoring of the 

cost-based portion of the rates. In addition, we propose that public utilities currently 

providing jurisdictional services and recovering costs of the services under market-based 

rates that have been granted waiver of the accounting and reporting requirements that seek 

recovery of a portion of service costs under cost-based rates, be required to forego the 

previously issued waiver and account for and report all cost and operational information to 

the Commission in accordance with its accounting and reporting requirements. In this 
Docket Nos. RM11-24-000 and AD10-13-000 - 52 -

instance, public utilities would be required to account for and report costs sought to be 

recovered on a cost-based and market-based basis. We seek comment on these proposals. 

Also, we seek comment on whether there should be a percentage of cost recovery 

threshold91 or other determining factor that triggers the accounting and reporting 

obligations in this situation, or should any instance of multiple cost recovery, regardless of 

the percentage of a utility’s total costs, trigger the accounting and reporting obligations. If 

a percentage threshold should apply, we seek comment with supporting rationale on what 

would be an appropriate threshold percentage.

76. Except as discussed above, the proposed amendments to the accounting and 

reporting regulations are not intended to affect the Commission’s policy on market-based 

rate authority as provided in Order No. 697 or its historical practice of granting waiver of 

the accounting and reporting regulations of 18 CFR Parts 41, 101, and 141 to certain 

entities with market-based rate authority. In Order No. 697, the Commission concluded 

that the costs of complying with the USofA requirements and, specifically Parts 41, 101, 

and 141 of the Commission’s regulations, outweigh any incremental benefits of such 

compliance where the seller only transacts at market-based rates.92 These proposed 

accounting and reporting rules do not change that conclusion. However, the Commission 

notes that entities authorized to make market-based rate sales, irrespective of accounting or 

 91 For example, a public utility with 90 percent of its service costs recovered under 

market-based rates and the remaining 10 percent recovered under cost-based rates. 

92 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 985.
Docket Nos. RM11-24-000 and AD10-13-000 - 53 -

other waivers, must file electric quarterly transaction reports regarding their transactions 

pursuant to Order No. 2001.93

77. At this time, the proposed accounting and reporting rules do not impose additional 

accounting or reporting requirements for hydroelectric pumped storage plant. The existing 

accounting and reporting standards use subaccounts for pumped storage under the 

functional classification of production, which is the only Commission-approved 

jurisdictional use of pumped storage to date. While the Commission has no basis to 

believe it is impossible to use large-scale pumped storage technologies to perform 

transmission or distribution functions as well, to date, no pumped storage developer has 

successfully demonstrated such a non-“production” use to the Commission. This stands in 

contrast to the track record for smaller-scale energy storage technologies, where one 

battery developer has successfully supported a non-production, transmission use for its 

project.94 The Commission remains open to future additions of pumped storage 

subaccounts to the transmission and distribution functions if appropriate, but at this time 

the Commission believes that the assets and operations of this pumped storage equipment 

 93 Revised Public Utility Filing Requirements, Order No. 2001, FERC Stats. & 

Regs. ¶ 31,127 (2002), reh’g denied, Order 2001-A, 100 FERC ¶ 61,074 (2002), reh’g

denied, Order No. 2001-B, 100 FERC ¶ 61,342 (2002), order directing filings, Order No. 

2001-C, 101 FERC ¶ 61,314 (2002), order directing filings, Order No. 2001-D, 102 FERC 

¶ 61,334, order refining filing requirements, Order No. 2001-E, 105 FERC ¶ 61,352 

(2003), clarified, Order No. 2001-F, 106 FERC ¶ 61,060 (2004), order on reh’g, Order 

No. 2001-G, 120 FERC ¶ 61,270 (2007), order on reh’g, Order No. 2001-H, 121 FERC 

¶ 61,289 (2007), order revising filing requirements, Order No. 2001-I, FERC Stats. & 

Regs. ¶ 31,282 (2008).

94 See Western Grid Development, LLC, 130 FERC ¶ 61,056, reh’g denied, 

133 FERC ¶ 61,029 (2010) (Western Grid).
Docket Nos. RM11-24-000 and AD10-13-000 - 54 -

are sufficiently accounted for by the existing FERC accounts and schedules of the Form 

Nos. 1, 1-F and 3-Q.95 

a. Electric Plant Accounts

78. The existing primary plant accounts do not explicitly provide for recording the 

original cost of energy storage assets. This can lead to inconsistent accounting and 

reporting for these assets by utilities subject to the accounting and reporting requirements, 

making it difficult for the Commission and others to determine costs related to energy

storage assets for cost-of-service rate purposes. In addition, the lack of transparency 

affects interested parties’ and including the Commission’s ability to monitor these 

companies operations to prevent and discourage cross-subsidization between cost-based 

and market-based activities. 

79. To provide more transparency for the costs of energy storage assets, as well as to 

address the possibility of inconsistent accounting and reporting, we propose creating a new 

electric plant account and amending two existing electric plant accounts to record the 

installed cost of energy storage equipment owned by public utilities and licensees. 

Specifically, we propose a new account within the production functional classification and 

amending existing accounts within the transmission and distribution functional 

classifications. 

80. The proposed plant account would be Account 348, Energy Storage EquipmentProduction, and the accounts we propose to amend are existing Account 351, [Reserved], 

 95 See FERC Account Nos. 330 – 337 and 535 – 545.1, 18 CFR Part 101 (2011); 

and Form Nos. 1, 1-F, and 3-Q, 18 CFR Part 141 (2011).
Docket Nos. RM11-24-000 and AD10-13-000 - 55 -

and Account 363, Storage Battery Equipment. Account 351 is a reserve account and is not 

currently being used. The Commission proposes to rename Account 351 as Energy 

Storage Equipment-Transmission. The current instructions of Account 363 provides for 

the inclusion of the cost of storage battery equipment used for the purpose of supplying 

electricity to meet emergency or peak demands. The Commission proposes to amend the 

instructions of Account 363 to expand the type of energy storage assets that can be 

recorded in the account and to recognize the unique operating characteristics of energy 

storage assets, which may provide services other than only supplying electricity.96 In 

addition, we also propose to rename Account 363 as Energy Storage EquipmentDistribution. 

81. The Commission proposes that the instructions to the accounts provide for 

recording the cost of installed energy storage assets based on the function or purpose the 

equipment serves. Further, we propose that in instances where an energy storage asset is 

used to perform more than one function or purpose, the cost of the asset shall be allocated 

among production, transmission, and distribution plant based on the services provided by 

the asset and the allocation of the asset’s cost through cost based rates approved by a 

relevant regulatory agency, federal or state. For example, if a relevant State Commission

under its own retail rate-setting authority approves the recovery of 25 percent of the cost 

installed of the storage device through the distribution component of retail rates, then we 

 96 For example, as a distribution resource recorded in the account the asset could 

assist with voltage regulation which may require it to absorb electricity rather than only 

supply it at times.
Docket Nos. RM11-24-000 and AD10-13-000 - 56 -

would expect 25 percent of the cost installed of the asset to be allocated to distribution 

plant for accounting and reporting purposes and we would expect distribution-related 

O&M and other accounting and reporting entries to likewise match relevant decisions 

made in the State Commission rate proceeding. If other portions of the cost installed are 

also approved for inclusion in cost-based rates at either a state or federal level, then the 

relevant decisions in those state or federal proceedings would apply to accounting and

reporting entries as well. The Commission seeks comments on these aspects of our 

proposal.

82. Additionally, the Commission proposes that the original cost of an energy storage 

asset and other amounts associated with the original cost of the asset (e.g., accumulated 

depreciation expenses and accumulated deferred income taxes) initially allocated to 

specific FERC accounts and later reallocated to other FERC accounts based on services 

provided by the asset and cost recovery be accounted for in accordance with Electric Plant 

Instruction No. 12, Transfers of Property.97 Accordingly, we propose that if the costs of 

an energy storage asset are included in the development of cost-based rates, then the same 

allocation of costs the primary rate-setting body used for rate development will also be 

used to allocate the original cost of the energy storage asset among the various functions

for accounting and reporting purposes. The Commission seeks comment on these 

proposals, including the accounting for the transfer of costs associated with an energy 

storage asset from one functional classification to another. Finally, we propose that the 

 97 18 CFR Part 101 (2011).
Docket Nos. RM11-24-000 and AD10-13-000 - 57 -

cost of energy storage assets be charged to depreciation expense using the depreciation 

rates developed for each function. 

83. Since some energy storage equipment may perform multiple functions on the grid, 

we propose that public utilities be required to maintain records identifying the types of 

functions each individual energy storage asset supports and performs. 

84. Additionally, the Commission proposes that costs to install energy storage 

equipment, along with power purchased or internally generated to energize the equipment 

to prepare it for service, be capitalized as a component cost of the equipment on the first 

installation only. This includes costs associated with power purchased and internally 

generated to test the equipment in preparation for utility service prior to it becoming ready 

for or placed in service.98 Further, we propose that earnings resulting from revenue 

received or earned for energy storage operations during test runs be credited to the cost of 

construction of the project.99 

85. Certain energy storage assets are capable of being moved from one location to 

another. These mobile assets are suitable for a wide range of applications, including 

emergency power and reliability, among other uses. Labor, materials and other costs are 

associated with moving these energy storage assets from one location to another location, 

resetting and preparing them to provide service, and purchasing or self-generating power 

to reenergize the assets. We propose that any costs incurred to remove, relocate, reset or 

 98 See Electric Plant Instruction No. 9(D), Equipment, 18 CFR Part 101 (2011).

99 See, e.g., Electric Plant Instruction No. 3(A)(18), Earnings and Expenses During 

Construction, 18 CFR Part 101 (2011).
Docket Nos. RM11-24-000 and AD10-13-000 - 58 -

reenergize an energy storage asset after it was first placed into utility service would not be 

chargeable to the energy storage equipment accounts as a cost component of the energy 

storage asset. Instead, the Commission proposes that such costs be accounted for as a 

production, transmission, or distribution expense based on the services provided by the 

energy storage asset and recovery of the asset’s cost through rates, in the accounts that 

follow.

100

86. The Commission proposes requiring that expenses other than power expenses for

removing, relocating or resetting energy storage plant serving a production function be 

charged to Account 548.1, Operation of Energy Storage Equipment, and Account 553.1, 

Maintenance of Energy Storage Equipment. We propose requiring that expenses other 

than power expenses for removing, relocating or resetting energy storage plant serving a 

transmission function be charged to Account 562.1, Operation of Energy Storage 

Equipment, and Account, 570.1, Maintenance of Energy Storage Equipment. Also, we 

propose requiring that expenses other than power expenses for removing, relocating or 

resetting energy storage plant serving a distribution function be charged to Account 582.1, 

Operation of Energy Storage Equipment, and Account592.2, Maintenance of Energy

Storage Equipment.

87. Finally, the Commission proposes that costs incurred to purchase or internally 

generate power to reenergize an energy storage asset after it was first put into service be 

charged as a current operating cost in the appropriate expense accounts for recording such 

 100 These proposed energy storage O&M expense accounts are discussed in more 

detail below at section 1(c).
Docket Nos. RM11-24-000 and AD10-13-000 - 59 -

costs, including the proposed purchased power account discussed below. The 

Commission seeks comment on its proposals regarding electric plant accounts and whether 

the proposed changes adequately provide for recording the cost of new energy storage 

technologies and the development of cost of service rates.

b. Power Purchased and Fuel Supply Expense Accounts 

88. To provide some electrical services, energy storage devices may need to maintain a 

particular state of charge, or as in the case of compressed air facilities, may need to 

maintain some minimum pressure. To maintain the desired state of charge or pressure 

some companies may be required to purchase power in retail or wholesale markets to 

energize their energy storage devices and other companies may internally generate power. 

In the NOI, the Commission asked about the accounting for the cost of power, fuel and 

other direct costs incurred in energy storage operations. Specifically, the Commission

asked about accounting for the cost of (1) power purchased and stored for resale; (2) 

power purchased that will not be resold but instead consumed in operations during the 

provisioning of services; (3) power purchased to sustain a state of charge; (4) power 

purchased to initially attain a state of charge; and (5) fuel or other direct costs incurred to 

internally generate power.101 

89. California Storage Alliance and ESA recommend that a new expense account 

entitled “Power Purchased for Storage Operations” be created to account for items 1-3 

above. They indicate that the account could also be used to account for item 4 if the costs 

 101 NOI, 135 FERC ¶ 61,240 at PP 38 – 44. 
Docket Nos. RM11-24-000 and AD10-13-000 - 60 -

are expensed as incurred; otherwise, they recommend that the costs be capitalized in the 

total cost of the storage resource.102 California Storage Alliance states that a benefit of 

having a separate account for power purchased for energy storage operations is that energy 

storage operating costs, which are organized on a plant level, can be distinguished from 

traditional utility power purchases and exchanges of electricity, which are organized on a 

company level. 

90. As stated above, the Commission proposes that item 4 and 5 costs of power 

purchased or internally generated to initially attain a state of charge in preparation for 

service prior to the equipment being ready for or placed in service be capitalized as a 

component cost of the equipment. Additionally, we propose that item 5 costs incurred 

later be expensed as incurred and accounted for as an expense of the accounting period. 

Regarding items 1-3, the Commission agrees with California Storage Alliance that there is 

a benefit to having the cost of power purchased for energy storage operations reported 

separate from other power purchases. This accounting is expected to enhance the 

transparency of reported cost, which is consistent with the goals of this proposed 

rulemaking. However, we do not agree with California Storage Alliance’s 

recommendation that power purchased for energy storage operations be accounted for and 

reported at the individual plant level. 

91. California Storage Alliance did not discuss this idea in any detail. It is not clear 

that information is needed to be reported at the individual plant level for rate development, 

 102 California Storage Alliance Comments at 32-34; ESA Comments at 39-41.
Docket Nos. RM11-24-000 and AD10-13-000 - 61 -

transparency, or any other purposes. Consequently, rather than proposing that power 

purchased for energy storage operations be accounted for at the individual plant level, the 

Commission proposes that the cost of power purchased for energy storage operations be 

accounted for at the company level in new Account 555.1, Power Purchased for Storage 

Operations. In that case, companies with multiple energy storage plant assets will record 

the costs of all power purchased for energy storage operations in one account similar to the 

procedures used to account for power purchased for other purposes that are currently 

recorded in Account 555, Purchased Power. However, we also propose that companies 

maintain records of costs associated with operation of a particular energy storage asset as 

required by 18 CFR Part 125. 

92. Further, the Commission proposes that the instructions to Account 555.1 shall be 

the same as those of Account 555 with an additional instruction requiring the cost of 

power purchased and consumed or lost in energy storage operations during the 

provisioning of services be recorded in the new account.103 

93. In regards to item 5 above, California Storage Alliance and ESA recommend that 

the cost of fuel incurred to internally generate power for use in energy storage operations 

be recorded in a new account entitled “Storage Fuel” and other direct costs incurred in 

such operations be recorded in new accounts entitled “Operation of Electric Storage 

 103 For example, purchased power may be consumed or lost during the conversion 

process where electric energy is received from the grid, stored as another form of energy 

and later transmitted to the grid as electric energy. 
Docket Nos. RM11-24-000 and AD10-13-000 - 62 -

Equipment” and “Maintenance of Electric Storage Equipment.”104 California Storage 

Alliance and ESA do not explain the benefit of recording the cost of fuel for this purpose 

in a new account. While this accounting may enhance transparency to some extent, 

existing fuel accounts can adequately support recording the costs of fuel used in energy 

storage operations. 

94. Generating companies currently account for fuel costs in FERC accounts by the 

method of production (i.e., steam, nuclear, hydraulic, or other). Recording fuel cost to a 

new storage fuel account would require these companies to calculate the amount of their 

total fuel costs to be allocated to energy storage operations. This data may best be 

reported in a new or existing schedule of the Form Nos. 1 and 1-F rather than in a new 

storage fuel account. California Storage Alliance and ESA’s recommended O&M expense 

accounts are discussed in the next section.

c. Operation and Maintenance Expense Accounts

95. As previously indicated there are O&M expenses related to the use of these energy 

storage assets to provide utility services and there are no existing O&M expense accounts 

in the USofA specifically dedicated to accounting for the cost of energy storage 

operations. EEI comments that, as it relates to the transmission function, the current O&M 

expense accounts would adequately provide for recording expenses associated with 

 104 California Storage Alliance Comments at 34 and 37; ESA Comments at 41 

and 45.
Docket Nos. RM11-24-000 and AD10-13-000 - 63 -

operation and maintenance of energy storage assets.105 The Commission agrees that there 

are some existing O&M expense accounts that can adequately support energy storagerelated operation and maintenance activities. We also believe current O&M expense 

accounts for the production and distribution functions can provide for recording some 

energy storage-related expenses. However, the operations and maintenance of certain 

energy storage assets may differ from conventional assets.106 Further, some existing O&M 

expense accounts may not be well suited to record the cost of certain activities associated 

with energy storage operations.107 To the extent that there are activities and associated 

costs of energy storage operations that are not specifically provided for in the existing 

O&M expense accounts, there is a need for accounts to report the costs. 

96. California Storage Alliance and ESA recommended that all energy storage-related 

O&M expense costs be recorded in new accounts entitled “Operation of Electric Storage 

Equipment” and “Maintenance of Electric Storage Equipment.” However, aggregating all 

 105 EEI Comments at 12. EEI indicated that in instances where energy storage 

assets provide a transmission function, the following O&M accounts associated with 

transmission can be used: Accounts 560, 561.5, 561.8, 562-564, 566-576.

106 For example, the procedures and practices involving repair of a flywheel that 

serves a transmission function may not be the same as the procedures and practices 

involving repair of a transmission line.

107 For example, certain O&M expenses for generator equipment used in storage 

operations that serves a transmission function are not well suited for recording in existing 

transmission O&M expense accounts. Such expenses are the type of expenses that would 

typically be incurred in production operations; however, because the generator equipment 

serves a transmission function, the nature of the expense is not production. In such cases, 

the O&M expenses for generator equipment should be recorded as a transmission expense

using the appropriate energy storage equipment transmission O&M expense account.
Docket Nos. RM11-24-000 and AD10-13-000 - 64 -

of the O&M costs for energy storage into two accounts reduces the transparency of the 

amounts reported, which is contrary to the purpose of the rulemaking. Further, because 

certain costs of energy storage operations can be adequately accounted for in the existing 

O&M expense accounts the costs should be reported there in accordance with the 

instructions of the accounts. Consequently, the Commission proposes that companies 

record energy storage-related O&M expenses in the existing O&M expense accounts 

according to the nature of the expense to the extent that the account adequately supports 

recording of the cost. 

97. For energy storage-related O&M expenses that are not specifically provided for in 

the existing O&M expense accounts the Commission proposes that such costs be recorded 

in Account 548.1, Operation of Energy Storage Equipment, and Account 553.1, 

Maintenance of Energy Storage Equipment, for energy storage plant classified as 

production; Account 562.1, Operation of Energy Storage Equipment, and Account 570.1, 

Maintenance of Energy Storage Equipment, for energy storage plant classified as 

transmission; and Account 582.1, Operation of Energy Storage Equipment, and 

Account592.2, Maintenance of Energy Storage Equipment, for energy storage plant 

classified as distribution. 

98. The Commission proposes that the instructions of the accounts provide for the 

inclusion of the cost of labor, materials used and expenses incurred in the operation and 

maintenance, as appropriate, of energy storage equipment, to the extent that the costs are 

not appropriately recorded in other O&M expense accounts. Furthermore, we propose that 

Accounts 592, Maintenance of Station Equipment (Major only), and 592.1, Maintenance 

of Structures and Equipment (Nonmajor only), be revised such that the accounts do not 
Docket Nos. RM11-24-000 and AD10-13-000 - 65 -

include O&M expenses related to energy storage operations. Additionally, we propose 

that the instructions of these accounts be revised to remove the reference to Account 363. 

The Commission seeks comment on its proposal, including whether the operations of 

certain energy storage assets differ enough from conventional assets or maintenance 

activities to require the proposed revisions. 

d. No New Revenue Accounts

99. In the NOI, the Commission asked whether new revenue accounts should be created 

or existing revenue accounts used to account for revenue associated with energy storage 

operations. The Commission also asked whether all revenues for energy storage 

operations should be recorded in a single revenue account: Account 456, Other Electric 

Revenues. Most commenters oppose recording all revenues associated with energy 

storage operations in a single account because it would not provide sufficient transparency 

as to the relation of the revenue to a particular service provided. Some commenters argue 

that new revenue accounts were needed to account for revenues generated using energy 

storage assets.108 These commenters generally argue that the existing revenue accounts do 

not provide sufficient transparency. However, commenters opposed to creating new 

revenue accounts argue that production, transmission, and distribution services currently 

have adequate revenue accounts, and energy storage technologies will simply comprise a 

component of those services. These commenters contend that revenue derived from the 

use of energy storage assets will originate from the same type of activities associated with 

 108 See, e.g., TAPS Comments at 17-18; BrightSource Comments at 7; and Viridity

Comments at 4.
Docket Nos. RM11-24-000 and AD10-13-000 - 66 -

revenue derived from the use of traditional utility assets.109 They argue that the type of 

resource used to provide the service does not change the accounting for the associated 

revenue.

100. The Commission agrees with commenters who contend that the existing revenue 

accounts sufficiently provide for accounting for revenue associated with using energy 

storage assets. We also agree that revenues associated with the use of energy storage 

assets will originate from the same type of activities associated with revenue derived from 

the use of traditional utility assets. The current revenue accounts provide for recording 

revenue based on sales of electricity and other products and services by type of customer, 

product, or service. Revenue derived from the operation of energy storage assets will 

originate from one or more of these items. Commenters recommending new accounts 

have not identified new revenue streams that may require different accounting. As such, 

the Commission does not propose new revenue accounts for energy storage. Companies 

using energy storage assets to provide utility service must record revenues associated with 

use of the assets in existing revenue accounts in accordance with the instructions of the 

accounts, as appropriate. 

2. Proposed New and Amended Form Nos. 1, 1-F, and 3-Q Schedules

101. The Form Nos. 1, 1-F, and 3-Q have schedules that include a basic set of financial 

statements: Comparative Balance Sheet, Statement of Income and Retained Earnings, 

Statement of Cash Flows, and the Statement of Comprehensive Income and Hedging 

 109 See, e.g., California Storage Alliance Comments at 34; ESA Comments at 42; 

and FirstEnergy Comments at 5.
Docket Nos. RM11-24-000 and AD10-13-000 - 67 -

Activities. Supporting schedules with supplementary information are filed, including 

revenues and the related quantities of products sold or transported; account balances for

O&M expenses; selected plant cost and operational data; and other information. The Form 

No. 1 provides schedule pages 408-409, Pumped Storage Generating Plant Statistics 

(Large Plants), and pages 410-411, Generating Plant Statistics (Small Plants) to report, 

among other items, operational information on pumped storage plants. These are the only 

schedules that provide for reporting information on energy storage and these schedules do 

not provide for reporting information on new types of energy storage assets such as 

batteries and flywheels, or allow any possibility of treating pumped storage plants as 

anything other than generating assets.

102. Several commenters responded to the NOI’s inquiry about whether the Form Nos. 1 

and 1-F should be amended to capture data on energy storage assets and operations. 

Commenters recommend that certain existing schedules be revised to include energy 

storage assets and a new schedule be created to report operational and statistical data on 

the assets.110 The primary difference among the recommendations is the amount of detail 

proposed for inclusion in the new schedule. 

103. Some commenters recommend that the schedule include all input items that are 

included in the total amount of O&M expenses for an energy storage asset, similar to how 

O&M expenses and plant information are currently required to be reported in schedule 

 110 See, e.g., California Storage Alliance Comments at 41; ESA Comments at 49; 

and TAPS Comments at 16.
Docket Nos. RM11-24-000 and AD10-13-000 - 68 -

pages 408-409 of the Form No. 1.111 In contrast, other commenters propose that the 

information be presented at a higher, aggregated, level with only total operation and total 

maintenance expense for energy storage operations reported in the schedule. The Form 

No. 1 provides schedule pages 408-409 for reporting detailed plant and O&M expense 

information on generating plants that are considered “large” and less detailed plant and 

cost information on generating plants that are considered “small” in schedule pages 

410-411, Generating Plant Statistics (Small Plants). According to the instructions of these 

schedules, the specific schedule a utility must use to report its plant statistics and certain 

associated costs is determined by the installed capacity of the unit. Generating units with 

10,000 kilowatts or more of installed capacity will generally report this information in 

schedule pages 408-409.112 While this kilowatt threshold may be an appropriate measure 

of information reporting requirements for traditional generating plants, it may not be 

appropriate for new energy storage assets that in many instances will be rated below 

10,000 kilowatts. Consequently, the Commission seeks comment on what would be an 

appropriate kilowatt threshold for requiring utilities to report more detailed plant and cost 

information for energy storage plant. 

104. The Commission proposes to add two new schedules to the Form Nos. 1 and 1-F to

report statistical and cost data on energy storage plant. One schedule will require more 

 111 See, e.g., California Storage Alliance Comments at 39 – 42; and ESA Comments 

at 47 – 50. 

112 The 10,000 kW threshold is currently applied to gas-turbine, internal 

combustion, nuclear, and conventional hydro and pumped storage plants. There is a 

separate 25,000 kW threshold for steam plants (e.g., coal, oil). 
Docket Nos. RM11-24-000 and AD10-13-000 - 69 -

detailed information than the other to lessen the reporting burden on companies with small 

energy storage operations. We preliminarily propose that 10,000 kilowatts be the 

threshold for determining whether a filer reports more detailed information in proposed 

schedule pages 414 - 417, Energy Storage Operations (Large Plants), or less detailed 

information in proposed schedule pages 419 - 421, Energy Storage Operations (Small 

Plants). We propose that the following information be reported on pages 414 – 417 in the 

proposed schedule: (1) megawatts (MW) purchased, MW delivered to the grid to support 

production, transmission, or distribution operations, MW lost during conversion and 

discharge of energy, and MW sold; (2) Account No. 555.1, Power Purchased for Storage 

Operations; (3) cost of fuel used in energy storage operations; (4) revenue from the sale of 

stored energy by revenue account; (5) other energy storage-related cost incurred; (6) cost 

of energy storage plant recorded in Accounts 101, 103, 106, and 107 by actual or expected 

functional classification; (7) operation and maintenance expenses associated with each 

function; and (8) name and location of energy storage plant, by project, and functional 

classification.

105. Additionally, we propose that the following information be reported on pages 

419 - 421 in the proposed schedule: (1) cost of plant; (2) operation expenses excluding 

fuel; (3) maintenance expenses; (4) cost of fuel used in energy storage operations; (5) 

Account No. 555.1, Power Purchased for Storage Operations; (6) other energy storagerelated cost incurred; and (7) name and location of energy storage plant, by project, and 

functional classification. 

106. Finally, we propose to amend several schedules of the Form Nos. 1 and 1-F to 

include the proposed energy storage plant, purchased power and O&M expense accounts 
Docket Nos. RM11-24-000 and AD10-13-000 - 70 -

discussed above, and schedule page 397, Amounts Included in ISO/RTO Settlement 

Statements, of the Form No. 3-Q to include the proposed purchased power account.113 

The Commission seeks public comment on each of the proposals discussed above, 

including whether the proposed changes will provide sufficiently transparent information 

on the activities and costs of new energy storage assets and operations. 

III. Information Collection Statement

107. The collections of information below for this proposed rule have been submitted to 

the Office of Management and Budget (OMB) for review under Section 3507(d) of the 

Paperwork Reduction Act of 1995.114 OMB’s regulations require approval of certain 

information collection requirements imposed by agency rule.115 The Commission solicits 

comments on its need for this information, whether the information will have practical 

utility, the accuracy of burden and cost estimates, ways to enhance the quality, utility, and 

clarity of the information to be collected or retained, and any suggested methods for 

minimizing respondents’ burden, including the use of automated information techniques.

Burden Estimate and Information Collection Costs: The additional estimated annual 

public reporting burdens and costs for the requirements in this proposed rule are as 

follows.

Data 

Collection

Number of 

Respondents 

(a)

Change in 

the Number 

of Hours Per

Filings Per 

Respondent 

Per Year

Change in the 

Total Annual 

Hours for this 

Estimated 

Annual Cost 

(at $120/hr.)

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

114 See 44 U.S.C. 3507(d).

115 5 CFR 1320.11 (2011).
Docket Nos. RM11-24-000 and AD10-13-000 - 71 -

Filing

(b)

(c) Collection

(aXbXc=d)

(dX$120/hr.)

($)

Form No. 1 210 6 1 1,260 151,200

Form No. 1-F 5 6 1 30 3,600

Form No. 3-Q 213 1 116 3 639 76,680

FERC-917 

[includes 

18CFR 35.28 

Pro forma 

open-access 

transmission 

tariff (OATT)]

132 10 1 440 averaged 

over Years 1-3 

[1320 in Year 

1]

52,800 117

FERC-717 

[includes 

OASIS & 

posting data 

on self-supply 

ancillary 

services]

176 2 1 352 42,240

FERC-919 

[includes ‘20 

percent 

screen’]

155 7 1 1,085 130,200

TOTAL 3,806 

(averaged over 

Years1-3)

$456,720

Titles: FERC Form No. 1, “Annual Report of Major Electric Utilities, Licensees, and 

Others;” FERC Form No. 1-F, “Annual Report for Nonmajor Public Utilities and 

Licensees;” FERC Form No. 3-Q, “Quarterly Financial Report of Electric Utilities, 

Licensees and Natural Gas Companies;” FERC-917, “Non-discriminatory Open Access 

Transmission Tariff,” FERC-717, “Standards for Business Practices and Communication 

Protocols for Public Utilities,” and FERC-919, “Electric Rate Schedule Filings: Market 

 116 The Form No. 3-Q estimate is one hour since the information is already 

collected and will only require a minor separation of costs.

117 The burden in Year 1 is 1,320 hrs. The average annualized burden over Years 

1-3 is 440 hr. (1,320/3).
Docket Nos. RM11-24-000 and AD10-13-000 - 72 -

Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by 

Public Utilities.”

Action: Proposed revisions to information collections.

OMB Control Nos.: 1902-0021 (FERC Form No. 1); 1902-0029 (FERC Form No.

1-F); 1902-0205 (FERC Form No. 3-Q); 1902-0233 (FERC-917), 1902-0173 (FERC-717); 

and 1902-0234 (FERC-919).

Respondents: Public utilities, FERC licensees, and public utility transmission providers.

Frequency of responses: Annually (FERC Form Nos. 1 and 1-F); quarterly

(FERC Form No. 3-Q); and as needed (FERC-917, FERC-717, and FERC-919).

Necessity of the Information: The proposed rule would amend the Commission’s 

regulations to reflect changes occurring in the electric industry due to the availability of 

new energy storage technologies that can be used in the provision of large-scale utility 

operations. The addition of these plant accounts, and new and amended reporting forms, 

should enhance transparency and provide detailed information on transactions and events 

affecting public utilities and licensees that file reports with the Commission. Without 

specific instructions and accounts for recording and reporting the above transactions and 

events, inconsistent and incomplete accounting and reporting will likely result.

With regard to FERC-917, FERC-919, and FERC-717 the proposed rule would provide 

increased transparency in the determination of Regulation and Frequency Response 

requirements, historical ancillary service information, and ancillary service capacity in 

order to ensure that rates for that service remain just, reasonable, and not unduly 

discriminatory. 
Docket Nos. RM11-24-000 and AD10-13-000 - 73 -

Internal Review: The Commission has reviewed the requirements pertaining to the USofA 

and the reports it prescribes and determined that the proposed amendments are necessary 

because the Commission needs to establish uniform accounting and reporting requirements 

for the costs of utility assets and expenses incurred for providing services as part of a 

utility’s operations. The Commission has reviewed the requirements associated with the 

OATT, OASIS, and market power analysis and determined they are necessary to increase 

transparency and ensure that rates remain just, reasonable, and not unduly discriminatory.

108. These requirements conform to the Commission’s need for efficient information 

collection, communication, and management within the energy industry. The Commission 

has assured itself, through internal review, that there is specific, objective support for the 

burden estimates associated with the information collection requirements.

109. Interested persons may obtain information on the reporting requirements by 

contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE,

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], 

e-mail: DataClearance@ferc.gov, Phone (202) 502-8663, fax: (202) 273-0873.

Comments on the collections of information and associated burden estimates in the 

proposed rule should be sent to the Commission in this docket and may also be sent to the 

Office of Information and Regulatory Affairs, Office of Management and Budget, 

Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory

Commission]. For security reasons, comments to OMB should be submitted by e-mail 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. 
Docket Nos. RM11-24-000 and AD10-13-000 - 74 -

3-Q); 1902-0233 (FERC-917), 1902-0173 (FERC-717); and 1902-0234 (FERC-919) and 

Docket Number RM11-24.

IV. Environmental Analysis

110. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.118 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact Statement is required for this Final Rule under 

section 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the FPA relating to the 

filing of schedules containing all rates and charges for the transmission or sale subject to 

the Commission’s jurisdiction, plus the classification, practices, contracts, and regulations 

that affect rates, charges, classifications, and services.119

V. Regulatory Flexibility Act 

111. The Regulatory Flexibility Act of 1980 (RFA)120 generally requires a description 

and analysis of proposed rules that will have significant economic impact on a substantial 

number of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a proposed rule and that minimize any significant 

economic impact on a substantial number of small entities. The Small Business 

 118 Regulations Implementing the National Environmental Policy Act, Order No. 

486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles 

1986-1990 ¶ 30,783 (1987).

119 18 CFR § 380.4(a)(15) (2011).

120 5 U.S.C. 601-612.
Docket Nos. RM11-24-000 and AD10-13-000 - 75 -

Administration’s (SBA) Office of Size Standards develops the numerical definition of a 

small business.121 The SBA has established a size standard for electric utilities, stating 

that a firm is small if, including its affiliates, it is primarily engaged in the transmission, 

generation and/or distribution of electric energy for sale and its total electric output for the 

preceding twelve months did not exceed four million megawatt hours.122 Most companies 

regulated by the Commission do not fall within the RFA’s definition of a small entity.123 

The proposed rule applies exclusively to public utilities that own, control, or operate 

facilities for transmitting electric energy in interstate commerce and not electric utilities 

per se. Based on the filers of the annual FERC Form No. 1 and Form No. 1-F, as well as 

the number of companies that have obtained waivers, we estimate that 6.8 percent of the 

filers affected by this proposed rule are “small.” The Commission believes this rule will 

not have a significant economic impact on a substantial number of small entities, and 

therefore no regulatory flexibility analysis is required. 

 121 13 CFR § 121.101 (2011).

122 13 CFR § 121.201, Sector 22, Utilities. 

123 See 5 U.S.C. 601(3) citing to section 3 of the Small Business Act, 15 U.S.C. 

632. Section 3 of the Small Business Act defines a “small-business concern” as a business 

which is independently owned and operated and which is not dominant in its field of 

operation. The Small Business Size Standards component of the North American Industry 

Classification System defines a small electric utility as one that, including its affiliates, is 

primarily engaged in generation, transmission, and/or distribution of electric energy for 

sale and whose total electric output for the preceding fiscal years did not exceed 4 million 

MWh. 13 CFR 121.201 (2011). 
Docket Nos. RM11-24-000 and AD10-13-000 - 76 -

VI. Comment Procedures

112. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due 60 days after 

publication in the FEDERAL REGISTER. Comments must refer to Docket No. 

RM11-24-000, and must include the commenter's name, the organization they represent, if 

applicable, and their address in their comments.

113. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts most 

standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper filing.

114. Commenters that are not able to file comments electronically must send an original 

of their comments to: Federal Energy Regulatory Commission, Secretary of the 

Commission, 888 First Street NE, Washington, DC 20426.

115. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section below. 

Commenters on this proposal are not required to serve copies of their comments on other 

commenters.

VII. Document Availability

116. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission's Home Page 
Docket Nos. RM11-24-000 and AD10-13-000 - 77 -

(http://www.ferc.gov) and in the Commission's Public Reference Room during normal 

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426.

117. From the Commission's Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field.

118. User assistance is available for eLibrary and the Commission’s website 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. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

List of subjects in 18 CFR Parts 35, 101 and 141 

Electric power rates; Electric utilities

By direction of the Commission. Commissioner Clark voting present.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket Nos. RM11-24-000 and AD10-13-000 - 78 -

In consideration of the foregoing, the Commission proposes to amend Parts 35, 37, 

101 and 141, 

Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS

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

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

§ 7101-7352.

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

§ 35.28 Non-discriminatory open access transmission tariff.

* * * * *

(c)(1)(viii) Each public utility’s open access transmission tariff, at Schedule 3 –

Regulation and Frequency Response Service, must include provisions explaining how it 

will determine its Regulation and Frequency Response reserve requirements. These 

provisions must take into account speed and accuracy of regulation resources and include a 

description of how the public utility transmission provider would make adjustments to the

capacity requirement when a customer opts to purchase from third-parties or self-supply 

its requirements using resources with speed and accuracy characteristics that differ from 

the set of resources otherwise being used for Regulation and Frequency Response Service.

3. Amend § 35.37 as follows:

a. Paragraph (c)(1) is revised.

b. New paragraph (c)(5) is added.
Docket Nos. RM11-24-000 and AD10-13-000 - 79 -

§ 35.37 Market power analysis required.

* * * * *

(c)(1) There will be a rebuttable presumption that a Seller lacks horizontal market 

power with respect to sales of energy, capacity, energy imbalance service, and generation 

imbalance service if it passes two indicative market power screens: a pivotal supplier 

analysis based on annual peak demand of the relevant market, and a market share analysis 

applied on a seasonal basis. There will be a rebuttable presumption that a seller possesses 

horizontal market power with respect to sales of energy, capacity, energy imbalance

service, and generation imbalance service if it fails either screen.

(c)(5) There will be a rebuttable presumption that a Seller of Operating ReserveSpinning, Operating Reserve-Supplemental, Reactive Supply and Voltage Control, or 

Regulation and Frequency Response services lacks horizontal market power with respect 

to sales of the ancillary service in question if the amount of capacity in MWs (or, as 

applicable, MVARs) that it can dedicate to providing the ancillary service in the relevant 

geographic market, taking into account any reported historical locational requirements, is 

no more than 20 percent of the relevant reported aggregate requirement for that ancillary 

service as reported pursuant to § 37.6(k) of the Commission’s Regulations.

4. Amend § 35.38 as follows:

a. Paragraph (a) is revised.

b. Paragraph (b) is revised.

c. New paragraph (c) is added.
Docket Nos. RM11-24-000 and AD10-13-000 - 80 -

§ 35.38 Mitigation.

* * * * *

(a) A Seller that has been found to have market power in generation or ancillary 

services, or that is presumed to have horizontal market power in generation or ancillary 

services by virtue of failing or foregoing the relevant market power screens, as described 

in 35.37(c), may adopt the default mitigation detailed in paragraph (b) of this section for 

sales of energy or capacity or paragraph (c) of this section for sales of ancillary services or 

may propose mitigation tailored to its own particular circumstances to eliminate its ability 

to exercise market power. Mitigation will apply only to the market(s) in which the Seller 

is found, or presumed, to have market power. 

(b) Default mitigation for sales of energy or capacity consists of three distinct 

products:

* * * * *

(c) Default mitigation for sales of ancillary services consists of: (1) a cost-based 

cap based on the relevant OATT ancillary service rate of the purchasing public utility 

transmission operator; (2) a cost-based cap based on the highest relevant public utility 

OATT ancillary service rate in the proposed trading area; or (3) the results of a 

competitive solicitation that meets the Commission’s requirements for transparency,

definition, evaluation, oversight, and adequate seller interest to ensure competitiveness. 

5. Amend § 37.6 by adding a new paragraph (k) as follows.
Docket Nos. RM11-24-000 and AD10-13-000 - 81 -

§ 37.6 Information to be posted on the OASIS. 

* * * * *

(k) Posting data related to historical ancillary service requirements. The 

Transmission Provider must post on OASIS information as to the aggregate amount (MW 

or MVAR, as applicable) of Operating Reserve-Spinning, Operating ReserveSupplemental, Reactive Supply and Voltage Control, and Regulation and Frequency 

Response services that it has historically required in order to serve its long-term firm 

obligations, including any geographic limitations it may face in meeting such ancillary 

service requirements.. 

PART 101 - UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC

UTILITIES AND LICENSEES SUBJECT TO THE PROVISIONS OF THE

FEDERAL POWER ACT

6. 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.

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

Electric Plant Chart of Accounts

* * * * *

2. PRODUCTION PLANT
Docket Nos. RM11-24-000 and AD10-13-000 - 82 -

* * * * *

D. OTHER PRODUCTION

* * * * *

348 Energy Storage Equipment-Production

* * * * *

8. In Part 101, Electric Plant Accounts, Account 351, the name of the account is 

amended and instructions are added to read as follows:

Electric Plant Accounts

* * * * *

351 Energy Storage Equipment-Transmission

A. This account shall include the cost installed of energy storage equipment used to 

store energy for load managing purposes. Where energy storage equipment can perform 

more than one function or 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 purchase and generation costs incurred to install and 

energize the equipment are includible on the first installation only. The cost of removing, 

relocating and resetting energy storage equipment shall not be charged to this account but 

to Account 562.1, Operation of Energy Storage Equipment, and Account 570.1, 
Docket Nos. RM11-24-000 and AD10-13-000 - 83 -

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

9. In Part 101, Electric Plant Accounts, Account 363, the name of the account and 

the instructions are amended to read as follows:

Electric Plant Accounts

* * * * *

363 Energy Storage Equipment-Distribution

A. This account shall include the cost installed of energy storage equipment used to 

store energy for load managing purposes. Where energy storage equipment can perform 

more than one function or purpose, the cost of the equipment shall be allocated among 

production, transmission, and distribution plant based on the services provided by the asset 

and the allocation of the asset’s cost through rates approved by a relevant regulatory 

agency. Reallocation of the cost of equipment recorded in this account shall be in 
Docket Nos. RM11-24-000 and AD10-13-000 - 84 -

accordance with Electric Plant Instruction No. 12, Transfers of Property.

B. Labor costs and power purchase and generation costs incurred to install and 

energize the equipment are includible on the first installation only. The cost of removing, 

relocating and resetting energy storage equipment shall not be charged to this account but 

to Account 582.1, Operation of Energy Storage Equipment, and Account 592.2, 

Maintenance of Energy Storage Equipment, as appropriate. 

C. The records supporting this account shall show, by months, the function(s) each 

energy storage asset supports or performs. 

ITEMS

1. Batteries/Chemical

2. Compressed Air

3. Flywheels

4. Superconducting Magnetic Storage

5. Thermal

10. In Part 101, Electric Plant Accounts, new primary plant account 348 is added to 

read as follows:
Docket Nos. RM11-24-000 and AD10-13-000 - 85 -

Electric Plant Accounts

* * * * *

348, Energy Storage Equipment-Production

A. This account shall include the cost installed of energy storage equipment used to 

store energy for load managing purposes. Where energy storage equipment can perform 

more than one function or purpose, the cost of the equipment shall be allocated among 

production, transmission, and distribution plant based on the services provided by the asset 

and the allocation of the asset’s cost through rates approved by a relevant regulatory 

agency. Reallocation of the cost of equipment recorded in this account shall be in 

accordance with Electric Plant Instruction No. 12, Transfers of Property.

B. Labor costs and power purchase and generation costs incurred to install and 

energize the equipment are includible on the first installation only. The cost of removing, 

relocating and resetting energy storage equipment shall not be charged to this account but 

to 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
Docket Nos. RM11-24-000 and AD10-13-000 - 86 -

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.

11. In Part 101, Operation and Maintenance Expense Chart of Accounts, Accounts 

548.1, 553.1, 555.1, 562.1, 570.1, 582.1, and 592.2 are added to the list:

Operation and Maintenance Expense Chart of Accounts

* * * * *

1. POWER PRODUCTION EXPENSES

* * * * *

D. OTHER POWER GENERATION 

* * * * *

Operation

* * * * *

548.1 Operation of Energy Storage Equipment

* * * * *

Maintenance

553.1 Maintenance of Energy Storage Equipment
Docket Nos. RM11-24-000 and AD10-13-000 - 87 -

* * * * *

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

* * * * *
Docket Nos. RM11-24-000 and AD10-13-000 - 88 -

582.1 Operation of Energy Storage Equipment

* * * * *

Maintenance

* * * * *

592.2 Maintenance of Energy Storage Equipment

12. In Part 101, Operation and Maintenance Expense Accounts, new operation 

expense account 548.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

548.1 Operation of Energy Storage Equipment

This account shall include the cost of labor, materials used and expenses incurred in 

the operation of energy storage equipment includible in Account 348, Energy Storage 

Equipment-Production, which are not specifically provided for or are readily assignable to 

other production operation expense accounts.

13. In Part 101, Operation and Maintenance Expense Accounts, new maintenance 

expense account 553.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

553.1 Maintenance of Energy Storage Equipment

This account shall include the cost of labor, materials used and expenses incurred in 
Docket Nos. RM11-24-000 and AD10-13-000 - 89 -

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.

14. In Part 101, Operation and Maintenance Expense Accounts, new power supply 

expense account 555.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

555.1 Power Purchased for Storage Operations

A. This account shall include the cost at point of receipt by the utility of electricity 

purchased for use in storage operations, including power purchased and consumed or lost 

in energy storage operations during the provision of services, including but not limited to 

energy purchased and stored for resale. It shall also include but not be limited to net 

settlements for exchange of electricity or power, such as economy energy, off-peak energy 

for on-peak energy, and spinning reserve capacity. In addition, the account shall include 

the net settlements for transactions under pooling or interconnection agreements wherein 

there is a balancing of debits and credits for energy, capacity, and possibly other factors. 

Distinct purchases and sales shall not be recorded as exchanges and net amounts only 

recorded merely because debit and credit amounts are combined in the voucher settlement.

B. The records supporting this account shall show, by months, the kilowatt hours 

and prices thereof under each purchase contract and the charges and credits under each 

exchange or power pooling contract.
Docket Nos. RM11-24-000 and AD10-13-000 - 90 -

15. In Part 101, Operation and Maintenance Expense Accounts, new operation 

expense account 562.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

562.1 Operation of Energy Storage Equipment

This account shall include the cost of labor, materials used and expenses 

incurred in the operation of energy storage equipment includible in Account 351, Energy 

Storage Equipment-Transmission, which are not specifically provided for or are readily 

assignable to other transmission operation expense accounts.

16. In Part 101, Operation and Maintenance Expense Accounts, new maintenance 

expense account 570.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

570.1 Maintenance of Energy Storage Equipment

This account shall include the cost of labor, materials used and expenses incurred in 

the maintenance of energy storage equipment includible in Account 351, Energy Storage 

Equipment-Transmission, which are not specifically provided for or are readily assignable 

to other transmission maintenance expense accounts.

17. In Part 101, Operation and Maintenance Expense Accounts, new operation 

expense account 582.1 is added to read as follows:
Docket Nos. RM11-24-000 and AD10-13-000 - 91 -

Operation and Maintenance Expense Accounts

* * * * *

582.1 Operation of Energy Storage Equipment

This account shall include the cost of labor, materials used and expenses incurred in 

the operation of energy storage equipment includible in Account 363, Energy Storage 

Equipment-Distribution, which are not specifically provided for or are readily assignable 

to other distribution operation expense accounts.

18. In Part 101, Operation and Maintenance Expense Accounts, new maintenance 

expense account 592.2 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

592.2 Maintenance of Energy Storage Equipment

This account shall include the cost of labor, materials used and expenses 

incurred in the maintenance of energy storage equipment includible in Account 363, 

Energy Storage Equipment-Distribution, which are not specifically provided for or are 

readily assignable to other distribution maintenance expense accounts.
Docket Nos. RM11-24-000 and AD10-13-000 - 92 -

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

Appendix A: List of Short Names of Commenters on the Federal Energy Regulatory 

Commission’s Notice of Inquiry on Third-Party Provision of Ancillary Services; 

Accounting and Financial Reporting for New Electric Storage Technologies – Docket 

No. RM11-24-000, June 2011

Short Name or Acronym Commenter

A123 A123 Systems, Inc.

AEP American Electric Power Service 

Corporation

AES Energy Storage AES Energy Storage 

APPA American Public Power Association 

Apparent Inc. Apparent Inc.

Aquion Energy, Inc. Aquion Energy, Inc.

AWEA American Wind Energy Association

Beacon Power Corporation Beacon Power Corporation

Bonneville Bonneville Power Administration

BrightSource BrightSource Energy, Inc. 

Business Council for Sustainable 

Energy

Business Council for Sustainable 

Energy

California PUC California Public Utilities Commission

California Storage Alliance California Energy Storage Alliance 

CAREBS Coalition to Advance Renewable 

Energy Through Bulk Storage

EEI Edison Electric Institute

Electricity Consumers Electricity Consumers Resource 

Council
Docket Nos. RM11-24-000 and AD10-13-000 - 93 -

ENBALA Enbala Power Networks

Environmental Defense Fund Environmental Defense Fund

EPSA Electric Power Supply Association 

ESA Electricity Storage Association 

FirstEnergy The Cleveland Electric Illuminating 

Company, Jersey Central Power & 

Light Company, Metropolitan Edison 

Company, Ohio Edison Company, 

Pennsylvania Electric Company, 

Pennsylvania Power Company, The 

Toledo Edison Company, Monongahela 

Power Company, The Potomac Edison 

Company, West Penn Power Company, 

FirstEnergy Solutions Corp., American 

Transmission Systems, Incorporated 

and Trans-Allegheny Interstate Line 

Company. 

FriiPwr FriiPwr USA 

Hydro Association National Hydropower Association 

IID Imperial Irrigation District

Mark Lively Mark B. Lively

National Grid National Grid USA 

National Park Service National Park Service

NaturEner NaturEner USA, LLC

NextStep NextStep Electric, LLC

NGK/TI NGK Insulators, Ltd and Technology 

Insights

NGSA Natural Gas Supply Association

Northwest Group Avista Corporation, Bonneville Power 
Docket Nos. RM11-24-000 and AD10-13-000 - 94 -

Administration, Chelan County PUD,

Clark Public Utilities, Cowlitz County 

PUD, Idaho Power Company, 

NorthWestern Energy, PacifiCorp, 

Public Power Council, Public Utility 

District No. 2 of Grant County, and 

Puget Sound Energy, Inc.

Portland General Portland General Electric Company

Powerex Powerex Corporation

PPL Companies PPL EnergyPlus, LLC and PPL 

Montana, LLC

Prudent Energy Prudent Energy Corporation

Public Interest Organizations Center for Rural Affairs, Clean 

Wisconsin, Climate + Energy Project, 

Conservation Law Foundation, 

Environment Northeast, Fresh Energy, 

Land Trust Alliance, Natural Resources 

Defense Council, Pace Energy and 

Climate Center, Project for Sustainable 

FERC Energy Policy, Sierra Club and 

Union of Concerned Scientists 

Riverbank Riverbank Power Corporation 

Saft Saft America, Inc.

SDG&E San Diego Gas & Electric Company 

Shell Energy Shell Energy North America (US), L.P.

Solar Energy Association Solar Energy Industries Association

SolarReserve SolarReserve LLC

Southern California Edison Southern California Edison Company

Starwood Starwood Energy Group Global, LLC

Steffes Steffes Corporation
Docket Nos. RM11-24-000 and AD10-13-000 - 95 -

TAPS Transmission Access Policy Study 

Group 

Viridity Viridity Energy Inc. 

WADE/Wartsila WADE USA and Wartsila North 

America

WSPP WSPP, Inc.

Xtreme Xtreme Power
Docket Nos. RM11-24-000 and AD10-13-000 - 96 -

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

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

Name of Respondent This Report is:

(1)  An O

(2)  

Date of Report 

(Mo, Da, Yr)

 / /

Year/Period of Report

End of Year/Qtr

LIST OF SCHEDULES (Electric Utility)

Enter in column (c) the terms “none”, “not applicable”, or “NA”, as appropriate, where no information or amounts have been 

reported for certain pages. Omit pages where the respondents are “none”, “not applicable”, or “NA”.

Line

No.

Title of Schedule

(a)

Reference 

Page No.

(b)

Remarks

(c)

1 General Information 101

2 Control Over Respondent 102

3 Corporations Controlled by Respondent 103

4 Officers 104

5 Directors 105

6 Information on Formula Rates 106(a)(b)

7 Important Changes During the Year 108-109

8 Comparative Balance Sheet 110-113

9 Statement of Income for the Year 114-117

10 Statement of Retained Earnings for the Year 118-119

11 Statement of Cash Flows 120-121

12 Notes to Financial Statements 122-123

13 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)

14 Summary of Utility Plant and Accumulated Provisions for Dep, Amort & Dep 200-201

15 Nuclear Fuel Materials 202-203

16 Electric Plant in Service 204-207

17 Electric Plant Leased to Others 213

18 Electric Plant Held for Future Use 214

19 Construction Work in Progress-Electric 216

20 Accumulated Provision for Depreciation of Electric Utility Plant 219

21 Investment of Subsidiary Companies 224-225

22 Materials and Supplies 227

23 Allowances 228-229

24 Extraordinary Property Losses 230

25 Unrecovered Plant and Regulatory Study Costs 230

26 Transmission Service and Generation Interconnection Study Costs 231

27 Other Regulatory Assets 232

28 Miscellaneous Deferred Debits 233

29 Accumulated Deferred Income Taxes 234

30 Capital Stock 250-251

31 Other Paid-in Capital 253

32 Capital Stock Expense 254

33 Long-Term Debt 256-257

34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261

35 Taxes Accrued, Prepaid and Charged During the Year 262-263

36 Accumulated Deferred Investment Tax Credits 266-267

FERC FORM NO. 1 (REV. 12-12) Page 2

FERC FORM NO. 1-F (REV. 12-12) 

 
Docket Nos. RM11-24-000 and AD10-13-000 - 97 -

Name of Respondent This Report is:

(1)  An Origina l

(2)  A Res ubmis

Date of 

Report 

(Mo, Da, 

Yr)

 / /

Year/Period of Report

End of Year/Qtr

LIST OF SCHEDULES (Electric Utility)

Enter in column (c) the terms “none”, “not applicable”, or “NA”, as appropriate, where no information or amounts have been reported for 

certain pages. Omit pages where the respondents are “none”, “not applicable”, or “NA”.

Line

No.

Title of Schedule

(a)

Reference 

Page No.

(b)

Remarks

(c)

37 Other Deferred Credits 269

38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273

39 Accumulated Deferred Income Taxes-Other Property 274-275

40 Accumulated Deferred Income Taxes-Other 276-277

41 Other Regulatory Liabilities 278

42 Electric Operating Revenues 300-301

43 Sales of Electricity by Rate Schedules 304

44 Sales for Resale 310-311

45 Electric Operation and Maintenance Expenses 320-323

46 Purchased Power 326-327

47 Transmission of Electricity for Others 328-330

48 Transmission of Electricity by ISO/RTOs 331

49 Transmission of Electricity by Others 332

50 Miscellaneous General Expenses-Electric 335

51 Depreciation and Amortization of Electric Plant 336-337

52 Regulatory Commission Expenses 350-351

53 Research, Development and Demonstration Activities 352-353

54 Distribution of Salaries and Wages 354-355

55 Common Utility Plant and Expenses 356

56 Amounts included in ISO/RTO Settlement Statements 397

57 Purchase and Sale of Ancillary Services 398

58 Monthly Transmission System Peak Load 400

59 Monthly ISO/RTO Transmission System Peak Load 400a

60 Electric Energy Account 401

61 Monthly Peaks and Output 401

62 Steam Electric Generating Plant Statistics 402-403

63 Hydroelectric Generating Plant Statistics 406-407

64 Pumped Storage Generating Plant Statistics 408-409

65 Generating Plant Statistics Pages 410-411

66 Energy Storage Operations (Large Plants) 414-416

67 Energy Storage Operations (Small Plants) 419-420

FERC FORM NO. 1 (REV. 12-12) Page 3

FERC FORM NO. 1-F (REV. 12-12) 
Docket Nos. RM11-24-000 and AD10-13-000 - 98 -

Name of Respondent This Report is:

(1)  An Origina l

(2)  

Date of Report 

(Mo, Da, Yr)

 / /

Year/Period of Report

End of Year/Qtr

LIST OF SCHEDULES (Electric Utility)

Enter in column (c) the terms “none”, “not applicable”, or “NA”, as appropriate, where no information or amounts have been 

reported for certain pages. Omit pages where the respondents are “none”, “not applicable”, or “NA”.

Lin

e

No.

Title of Schedule

(a)

Reference 

Page No.

(b)

Remarks

(c)

68 Transmission Line Statistics Pages 426-427

69 Substations 426-427

70 Transactions with Associated (Affiliated) Companies 429

71 Footnote Data 450

72 Stockholder’s Reports – Check appropriate box:

 Two copies will be s ubmitte d.

 No a nnua l re port to stockholde rs is pre pa re d.

FERC FORM NO. 1 (REV. 12-12) Page 4

FERC FORM NO. 1-F (REV. 12-12)
Docket Nos. RM11-24-000 and AD10-13-000 - 99 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)

1. Report below the original cost of electric plant in service according to the prescribed accounts.

2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;

Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.

3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.

4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in 

column (e) adjustments.

5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.

6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be 

included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a 

significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative 

distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include 

also in column (d)

Line 

No.

Accounts

(a)

Balance 

Beginning of Year 

(b)

Additions

(c)

1 1. INTANGIBLE PLANT

2 (301) Organization 

3 (302) Franchises and Consents

4 (303) Miscellaneous Intangible Plant

5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)

6 2. PRODUCTION PLANT 

7 A. Steam Production Plant

8 (310) Land and Land Rights

9 (311) Structures and Improvements

10 (312) Boiler Plant Equipment

11 (313) Engines and Engine-Driven Generators

12 (314) Turbogenerator Units

13 (315) Accessory Electric Equipment 

14 (316) Misc. Power Plant Equipment

15 (317) Asset Retirement Costs for Steam Production 

16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)

17 B. Nuclear Production Plant

18 (320) Land and Land Rights

19 (321) Structures and Improvements

20 (322) Reactor Plant Equipment

21 (323) Turbogenerator Units

22 (324) Accessory Electric Equipment

23 (325) Misc. Power Plant Equipment

24 (326) Asset Retirement Costs for Nuclear Production

25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)

26 C. Hydraulic Production Plant

27 (330) Land and Land Rights

28 (331) Structures and Improvements

29 (332) Reservoirs, Dams, and Waterways

30 (333) Water Wheels, Turbines, and Generators

31 (334) Accessory Electric Equipment

32 (335) Miscellaneous Power Plant Equipment

33 (336) Roads, Railroads, and Bridges

34 (337) Asset Retirement Costs for Hydraulic Production

35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)

36 D. Other Production Plant

37 (340) Land and Land Rights

38 (341) Structures and Improvements

39 (342) Fuel Holders, Products, and Accessories

40 (343) Prime Movers

41 (344) Generators

42 (345) Accessory Electric Equipment

43 (346) Misc. Power Plant Equipment

44 (347) Asset Retirement Costs for Other Production

45 (348) Energy Storage Equipment - Production

46 TOTAL Other Production Plant (Enter Total of lines 37 thru 45)

47 TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 46)

 FERC FORM NO. 1/1-F (REV. 12-12) Page 204
Docket Nos. RM11-24-000 and AD10-13-000 - 100 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)

Distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these

amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount 

of respondent’s plant actually in service at end of year.

7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account

classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated

provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary

account classifications.

8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing

subaccount classification of such plant conforming to the requirement of these pages.

9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,

and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give 

also date.

Retirements

(d)

Adjustments

 (e)

Transfers

 (f)

Balance at End of Year

(g)

Line

No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

 FERC FORM NO. 1/1-F (REV. 12-12) Page 205

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 
Docket Nos. RM11-24-000 and AD10-13-000 - 101 -

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)

Line

No.

Accounts

(a)

Balance Beginning 

of Year (b)

Additions

(c)

48 3. TRANSMISSION PLANT

49 (350) Land and Land Rights

50 (351) Energy Storage Equipment - Transmission

51 (352) Structures and Improvements

52 (353) Station Equipment

53 (354) Towers and Fixtures

54 (355) Poles and Fixtures

55 (356) Overhead Conductors and Devices

56 (357) Underground Conduit

57 (358) Underground Conductors and Devices

58 (359) Roads and Trails

59 (359.1) Asset Retirement Costs for Transmission Plant

60 TOTAL Transmission Plant (Enter Total of lines 49 thru 59)

61 4. DISTRIBUTION PLANT

62 (360) Land and Land Rights

63 (361) Structures and Improvements

64 (362) Station Equipment

65 (363) Energy Storage Equipment – Distribution

66 (364) Poles, Towers, and Fixtures

67 (365) Overhead Conductors and Devices

68 (366) Underground Conduit

69 (367) Underground Conductors and Devices

70 (368) Line Transformers

71 (369) Services

72 (370) Meters

73 (371) Installations on Customer Premises

74 (372) Leased Property on Customer Premises

75 (373) Street Lighting and Signal Systems

76 (374) Asset Retirement Costs for Distribution Plant

77 TOTAL Distribution Plant (Enter Total of lines 62 thru 76)

78 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT

79 (380) Land and Land Rights

80 (381) Structures and Improvements

81 (382) Computer Hardware

82 (383) Computer Software

83 (384) Communication Equipment

84 (385) Miscellaneous Regional Transmission and Market Operation Plant

85 (386) Asset Retirement Costs for Regional Transmission and Market Operation Plant

86 TOTAL Transmission and Market Operation Plant (Enter Total of lines 79 thru 85)

87 6. GENERAL PLANT

88 (389) Land and Land Rights

89 (390) Structures and Improvements

90 (391) Office Furniture and Equipment

91 (392) Transportation Equipment

92 (393) Stores Equipment

93 (394) Tools, Shop and Garage Equipment

94 (395) Laboratory Equipment

95 (396) Power Operated Equipment

96 (397) Communication Equipment

97 (398) Miscellaneous Equipment

98 SUBTOTAL (Enter Total of Lines 88 thru 97)

99 (399) Other Intangible Property

100 (399.1) Asset Retirement Costs for General Plant

101 TOTAL General Plant (Enter Total of Lines 98, 99 and 100)

102 TOTAL (Accounts 101 and 106)

103 (102) Electric Plant Purchased (See Instruction 8)

104 (Less) (102) Electric Plant Sold (See Instruction 8)

105 (103) Experimental Plant Unclassified

106 TOTAL Electric Plant in Service (Enter Total of lines 102 thru 1051)

 FERC FORM NO. 1/1-F (REV. 12-12) Page 206

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)

Retirements

(d)

Adjustments

 (e)

Transfers

 (f)

Balance at End of Year

(g)

Line

No.
Docket Nos. RM11-24-000 and AD10-13-000 - 102 -

48

49

50

51

52

53

54

55

56

57

58

59

60

61

62

63

64

65

66

67

68

69

70

71

72

73

74

75

76

77

78

79

80

81

82

83

84

85

86

 87

88

89

90

91

92

93

94

95

96

 97

98

99

100

101

102

 103

104

105

106

 FERC FORM NO. 1/1-F (REV. 12-12) Page 207

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC OPERATION AND MAINTENANCE EXPENSES

If the amount for previous year is not derived from previously reported figures, explain in footnote.

Line

No.

Account

(a)

Amount for Current 

Year

(b)

Amount for Previous Year

(c)
Docket Nos. RM11-24-000 and AD10-13-000 - 103 -

1 1. POWER PRODUCTION EXPENSES

2 A. Steam Power Generation

3 Operation

4 (500) Operation Supervision and Engineering

5 (501) Fuel

6 (502) Steam Expenses

7 (503) Steam from Other Sources

8 (Less) (504) Steam Transferred-Cr.

9 (505) Electric Expenses

10 (506) Miscellaneous Steam Power Expenses

11 (507) Rents

12 (509) Allowances

13 TOTAL Operation (Enter Total of Lines 4 thru 12)

14 Maintenance

15 (510) Maintenance Supervision and Engineering

16 (511) Maintenance of Structures

17 (512) Maintenance of Boiler Plant

18 (513) Maintenance of Electric Plant

19 (514) Maintenance of Miscellaneous Steam Plant

20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)

21 TOTAL Power Production Expenses-Steam Power (Enter Total lines 13 & 20)

22 B. Nuclear Power Generation

23 Operation

24 (517) Operation Supervision and Engineering

25 (518) Fuel

26 (519) Coolants and Water

27 (520) Steam Expenses

28 (521) Steam from Other Sources

29 (Less) (522) Steam Transferred-Cr.

30 (523) Electric Expenses

31 (524) Miscellaneous Nuclear Power Expenses

32 (525) Rents

33 TOTAL Operation (Enter Total of lines 24 thru 32)

34 Maintenance

35 (528) Maintenance Supervision and Engineering

36 (529) Maintenance of Structures

37 (530) Maintenance of Reactor Plant Equipment

38 (531) Maintenance of Electric Plant

39 (532) Maintenance of Miscellaneous Nuclear Plant

40 TOTAL Maintenance (Enter Total of lines 35 thru 39)

41 TOTAL Power Production Expenses-Nuclear Power (Enter Total of lines 33 & 40)

42 C. Hydraulic Power Generation

43 Operation

44 (535) Operation Supervision and Engineering

45 (536) Water for Power 

46 (537) Hydraulic Expenses

47 (538) Electric Expenses

48 (539) Miscellaneous Hydraulic Power Generation Expenses

49 (540) Rents

 50 TOTAL Operation (Enter Total of Lines 44 thru 49)

52 Maintenance

53 (541) Maintenance Supervision and Engineering

54 (542) Maintenance of Structures

55 (543) Maintenance of Reservoirs, Dams, and Waterways

56 (544) Maintenance of Electric Plant 

57 (545) Maintenance of Miscellaneous Hydraulic Plant

58 TOTAL Maintenance (Enter Total of lines 53 thru 57)

59 TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 and 58)

FERC FORM NO. 1 (REV. 12-12) Page 320
Docket Nos. RM11-24-000 and AD10-13-000 - 104 -

Name of Respondent This Report is: (1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)

Line

No.

Accounts

(a)

Amount for Current Year

(b)

Amount for Previous Year

(c)

60 D. Other Power Generation

61 Operation

62 (546) Operation Supervision and Engineering

63 (547) Fuel

64 (548) Generation Expenses

65 (548.1) Operation of Energy Storage Equipment

66 (549) Miscellaneous Other Power Generation Expenses

67 (550) Rents

68 TOTAL Operation (Enter Total of lines 62 thru 67)

69 Maintenance

70 (551) Maintenance Supervision and Engineering

71 (552) Maintenance of Structures

72 (553) Maintenance of Generating and Electric Plant

73 (553.1) Maintenance of Energy Storage Equipment

74 (554) Maintenance of Miscellaneous Other Power Generation Plant

75 TOTAL Maintenance (Enter Total of lines 70 thru 74)

76 TOTAL Power Production Expenses-Other Power (Enter Total of lines 68 & 75)

77 E. Other Power Supply Expenses

78 (555) Purchased Power

79 (555.1) Power Purchased for Storage Operations 

80 (556) System Control and Load Dispatching

81 (557) Other Expenses

82 TOTAL Other Power Supply Expenses (Enter Total of lines 78 thru 81)

83 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 76 & 82)

84 2. TRANSMISSION EXPENSES

85 Operation

86 (560) Operation Supervision and Engineering

87 (561.1) Load Dispatch-Reliability

88 (561.2) Load Dispatch-Monitor and Operate Transmission System

89 (561.3) Load Dispatch-Transmission Service and Scheduling

90 (561.4) Scheduling, System Control and Dispatch Services 

91 (561.5) Reliability, Planning and Standards Development

92 (561.6) Transmission Service Studies

93 (561.7) Generation Interconnection Studies

94 (561.8) Reliability, Planning and Standards Development Services

95 (562) Station Expenses

96 (562.1) Operation of Energy Storage Equipment

97 (563) Overhead Lines Expenses

98 (564) Underground Lines Expenses

99 (565) Transmission of Electricity by Others

100 (566) Miscellaneous Transmission Expenses

101 (567) Rents

102 TOTAL Operation (Enter Total of lines 85 thru 101)

103 Maintenance

104 (568) Maintenance Supervision and Engineering

105 (569) Maintenance of Structures

106 (569.1) Maintenance of Computer Hardware

107 (569.2) Maintenance of Computer Software

108 (569.3) Maintenance of Communication Equipment

109 (569.4) Maintenance of Miscellaneous Regional Transmission Plant

110 (570) Maintenance of Station Equipment

111 (570.1) Maintenance of Energy Storage Equipment

112 (571) Maintenance of Overhead Lines

113 (572) Maintenance of Underground Lines

114 (573) Maintenance of Miscellaneous Transmission Plant

FERC FORM NO. 1 (REV. 12-12) Page 321
Docket Nos. RM11-24-000 and AD10-13-000 - 105 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)

If the amount for previous year is not derived from previously reported figures, explain in footnote.

Line

No.

Account

(a)

Amount for 

Current Year

(b)

Amount for 

Previous Year

(c)

115 TOTAL Maintenance (Enter Total of lines 104 thru 114)

116 TOTAL Transmission Expenses (Enter Total of lines 102 and 115)

117 3. REGIONAL MARKET EXPENSES

118 Operation 

119 (575.1) Operation Supervision

120 (575.2) Day-Ahead and Real-Time Market Facilitation

121 (575.3) Transmission Rights Market Facilitation

122 (575.4) Capacity Market Facilitation 

123 (575.5) Ancillary Services Market Facilitation 

124 (575.6) Market Monitoring and Compliance

125 (575.7) Market Facilitation, Monitoring and Compliance Services

126 (575.8) Rents

127 Total Operation (Lines 119 thru 126) 

128 Maintenance 

129 (576.1) Maintenance of Structures and Improvements

130 (576.2) Maintenance of Computer Hardware

131 (576.3) Maintenance of Computer Software

132 (576.4) Maintenance of Communication Equipment

133 (576.5) Maintenance of Miscellaneous Market Operation Plant

134 Total Maintenance (Lines 129 thru 133) 

135 TOTAL Regional Transmission and Market Operation Expenses (Enter Total of lines 127 and 134)

136 4. DISTRIBUTION EXPENSES

137 Operation

138 (580) Operation Supervision and Engineering

139 (581) Load Dispatching

140 (582) Station Expenses

141 (582.1) Operation of Energy Storage Equipment

142 (583) Overhead Line Expenses

143 (584) Underground Line Expenses

144 (585) Street Lighting and Signal System Expenses

145 (586) Meter Expenses

146 (587) Customer Installations Expenses

147 (588) Miscellaneous Expenses

148 (589) Rents

149 TOTAL Operation (Enter Total of lines 138 thru 148)

150 Maintenance

151 (590) Maintenance Supervision and Engineering

152 (591) Maintenance of Structure

153 (592) Maintenance of Station Equipment

154 (592.2) Maintenance of Energy Storage Equipment

155 (593) Maintenance of Overhead Lines

156 (594) Maintenance of Underground Lines

157 (595) Maintenance of Line Transformers

158 (596) Maintenance of Street Lighting and Signal Systems

159 (597) Maintenance of Meters

160 (598) Maintenance of Miscellaneous Distribution Plant

161 TOTAL Maintenance (Enter Total of lines 151 thru 160)

162 TOTAL Distribution Expenses (Enter Total of lines 149 and 161)

FERC FORM NO. 1 (REV. 12-12) Page 322
Docket Nos. RM11-24-000 and AD10-13-000 - 106 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)

If the amount for previous year is not derived from previously reported figures, explain in footnote.

Line

No.

Account

(a)

Amount for Current Year

(b)

Amount for 

Previous Year

( ) 163 5. CUSTOMER ACCOUNTS EXPENSES

164 Operation

165 (901) Supervision

166 (902) Meter Reading Expenses

167 (903) Customer Records and Collection Expenses

168 (904) Uncollectible Accounts

169 (905) Miscellaneous Customer Accounts Expenses

170 TOTAL Customer Accounts Expenses (Total of lines 165 thru 169)

171 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES

172 Operation

173 (907) Supervision

174 (908) Customer Assistance Expenses

175 (909) Informational and Instructional Expenses

176 (910) Miscellaneous Customer Service and Informational Expenses

177 TOTAL Customer Service and Information. Expenses (Total lines 173 thru 176)

178 7. SALES EXPENSES

179 Operation

180 (911) Supervision

181 (912) Demonstrating and Selling Expenses

182 (913) Advertising Expenses

183 (916) Miscellaneous Sales Expenses

184 TOTAL Sales Expenses (Enter Total of lines 180 thru 184)

185 8. ADMINISTRATIVE AND GENERAL EXPENSES

186 Operation

187 (920) Administrative and General Salaries

188 (921) Office Supplies and Expenses

189 (Less) (922) Administrative Expenses Transferred-Credit

190 (923) Outside Services Employed

191 (924) Property Insurance

192 (925) Injuries and Damages

193 (926) Employee Pensions and Benefits

194 (927) Franchise Requirements

195 (928) Regulatory Commission Expenses

196 (929) (Less) Duplicate Charges-Cr.

197 (930.1) General Advertising Expenses

198 (930.2) Miscellaneous General Expenses

199 (931) Rents

200 TOTAL Operation (Enter Total of lines 187 thru 199)

201 Maintenance

202 (935) Maintenance of General Plant

203 TOTAL Administrative & General Expenses (Total of lines 199 and 201)

204 TOTAL Electric Operation and Maintenance Expenses (Total of lines 83, 116, 135, 162, 

170, 177, 184, and 203)

FERC FORM NO. 1 (REV. 12-12) Page 323
Docket Nos. RM11-24-000 and AD10-13-000 - 107 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC PRODUCTION, OTHER POWER SUPPLY, TRANSMISSION, REGIONAL MARKET, AND DISTRIBUTION EXPENSES

Report Electric production, other power supply expenses, transmission, regional market, and distribution expenses through the reporting period.

Line 

No.

Account

(a)

Year to Date

Quarter

1 1. POWER PRODUCTION AND OTHER SUPPLY EXPENSES

2 Steam Power Generation - Operation (500-509)

3 Steam Power Generation – Maintenance (510-515)

4 Total Power Production Expenses - Steam Power

5 Nuclear Power Generation – Operation (517-525)

6 Nuclear Power Generation – Maintenance (528-532)

7 Total Power Production Expenses - Nuclear Power

8 Hydraulic Power Generation – Operation (535-540.1)

9 Hydraulic Power Generation – Maintenance (541-545.1)

10 Total Power Production Expenses - Hydraulic Power

11 Other Power Generation – Operation (546-550.1)

12 Other Power Generation – Maintenance (551-554.1)

13 Total Power Production Expenses - Other Power

14 Other Power Supply Expenses

15 Purchased Power (555)

16 (555.1) Power Purchased for Storage Operations

17 System Control and Load Dispatching (556)

18 Other Expenses (557)

19 Total Other Power Supply Expenses (line 15-18)

20 Total Power Production Expenses (Total of lines 4, 7, 10, 13 and 19)

21 2. TRANSMISSION EXPENSES

22 Transmission Operation Expenses

23 (560) Operation Supervision and Engineering

24 (561.1) Load Dispatch-Reliability

25 (561.2) Load Dispatch-Monitor and Operate Transmission System

26 (561.3) Load Dispatch-Transmission Service and Scheduling

27 (561.4) Scheduling, System Control and Dispatch Services 

28 (561.5) Reliability, Planning and Standards Development

29 (561.6) Transmission Service Studies

30 (561.7) Generation Interconnection Studies

31 (561.8) Reliability, Planning and Standards Development Services

32 (562) Station Expenses

33 (562.1) Operation of Energy Storage Equipment

34 (563) Overhead Line Expenses

35 (564) Underground Line Expenses

36 (565) Transmission of Electricity by Others

37 (566) Miscellaneous Transmission Expenses

38 (567) Rents

39 (567.1) Operation Supplies and Expenses (Non-Major)

40 TOTAL Transmission Operation Expenses (Lines 23 – 39)

FERC FORM 3-Q (REV 12-12) Page 324a
Docket Nos. RM11-24-000 and AD10-13-000 - 108 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC PRODUCTION, OTHER POWER SUPPLY, TRANSMISSION, REGIONAL TRANSMISSION AND MARKET OPERATION, AND DISTRIBUTION 

EXPENSES

Report Electric production, other power supply expenses, transmission, regional control and market operation, and distribution expenses through the reporting 

period.

Line 

No.

Account

(a)

Year to Date

Quarter

41 Transmission Maintenance Expenses

42 (568) Maintenance Supervision and Engineering

43 (569) Maintenance of Structures

44 (569.1) Maintenance of Computer Hardware

45 (569.2) Maintenance of Computer Software

46 (569.3) Maintenance of Communication Equipment

47 (569.4) Maintenance of Miscellaneous Regional Transmission Plant

48 (570) Maintenance of Station Equipment

49 (570.1) Maintenance of Energy Storage Equipment

50 (571) Maintenance Overhead Lines

51 (572) Maintenance of Underground Lines

52 (573) Maintenance of Miscellaneous Transmission Plant

53 (574) Maintenance of Transmission Plant

54 TOTAL Transmission Maintenance Expenses (Lines 42 – 53)

55 Total Transmission Expenses (Lines 40 and 54)

56 3. REGIONAL MARKET EXPENSES

57 Regional Market Operation Expenses

58 (575.1) Operation Supervision

59 (575.2) Day-Ahead and Real-Time Market Facilitation

60 (575.3) Transmission Rights Market Facilitation

61 (575.4) Capacity Market Facilitation 

62 (575.5) Ancillary Services Market Facilitation 

63 (575.6) Market Monitoring and Compliance

64 (575.7) Market Facilitation, Monitoring and Compliance Services

65 Regional Market Operation Expenses (Lines 58–64 )

66 Regional Market Maintenance Expenses

67 (576.1) Maintenance of Structures and Improvements 

68 (576.2) Maintenance of Computer Hardware

69 (576.3) Maintenance of Computer Software

70 (576.4) Maintenance of Communication Equipment

71 (576.5) Maintenance of Miscellaneous Market Operation Plant

72 Regional Market Maintenance Expenses (Lines 67-71)

73 TOTAL Regional Control and Market Operation Expenses (Lines 65 and 72)

74 4. DISTRIBUTION EXPENSES

75 Distribution Operation Expenses (580-589)

76 Distribution Maintenance Expenses (590-598)

77 Total Distribution Expenses (Lines 75 and 76)

78 TOTAL (Lines 20, 55, 73, and 77)

FERC FORM 3-Q (REV 12-12) Page 324b
Docket Nos. RM11-24-000 and AD10-13-000 - 109 -

Name of Respondent This Report Is: 

(1)  An Origina l

(2)  A 

Date of Report 

(Mo, Da, Yr)

 / /

Year/Period of 

Report

End of Year/Qtr

PURCHASED POWER (Accounts 555 and 555.1)

(Including Power Exchanges)

1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for 

energy, capacity, etc.) and any settlements for imbalanced exchanges.

2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a 

footnote any ownership interest or affiliation the respondent has with the seller.

3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load 

for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service 

to its own ultimate consumers.

LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is 

intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of 

LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as 

LF, provide in a footnote the termination date of the contract

defined as the earliest date that either buyer or seller can unilaterally get out of the contract.

IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years.

SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less.

LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from 

transmission constraints, must match the availability and reliability of the designated unit.

IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but 

less than five years.

EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements 

for imbalanced exchanges.

OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service 

regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each 

adjustment.

Line

No.

Name of Company or Public Authority

(Footnote Affiliations)

(a)

Statistical 

Classification

(b)

FERC Rate 

Schedule or 

Tariff Number

(c)

Average

Monthly Billing

Demand (MW)

(d)

Actual Demand (MW)

Average

Monthly NCP 

Demand

Total

(e)

Average

Monthly CP 

Demand

(f)

MegaWatt

Hours

Purchased

(Excluding 

for Energy

Storage)

(g)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

Total

FERC FORM NO. 1 (REV. 12-12) Page 326

FERC FORM NO. 1-F (REV. 12-12)
Docket Nos. RM11-24-000 and AD10-13-000 - 110 -

Name of Respondent This Report Is: 

(1)  An Origina l

(2)  A 

Date of Report 

(Mo, Da, Yr)

 / /

Year/Period of 

Report

End of 

Year/Qtr

PURCHASED POWER (Accounts 555 and 555.1) (Continued)

(Including Power Exchanges)

AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an 

explanation in a footnote for each adjustment.

4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the 

contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided.

5. For requirements RQ purchases and any type of service involving demand charges imposed on a monthly (or longer) basis, enter the monthly average 

billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand 

in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute 

integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches 

its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.

6. Report in column (g) the megawatt hours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatt hours of power 

exchanges received and delivered, used as the basis for settlement. Do not report net exchange.

7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in 

column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as 

settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered 

than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes 

certain credits or charges covered by the agreement, provide an explanatory footnote.

8. The data in column (g) through (n) totals to the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 

10. The total amount in column (h) must be reported as Purchases for Energy Storage on Page 401, line 11. The total amount in column (i) must be reported 

as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 

9. Footnote entries as required and provide explanations following all required data.

MegaWatt Hours

Purchased for 

Energy Storage

(h)

POWER EXCHANGES COST/SETTLEMENT OF POWER Line

No.

MegaWatt Hours

Received

(i)

MegaWatt Hours

Delivered

(j)

Demand Charges

($)

(k)

Energy Charges

($)

(l)

Other Charges

($)

(m)

Total (k+ l+m)

of Settlement ($)

(n)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

FERC FORM NO. 1 (REV. 12-12) Page 327

FERC FORM NO. 1-F (REV. 12-12)
Docket Nos. RM11-24-000 and AD10-13-000 - 111 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS

1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, Account 555.1, Power 

Purchased for Storage Operations, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be 

separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. 

Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly 

sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, Account 555, Purchased Power, or Account 

555.1, Power Purchased for Storage Operations, respectively.

Line

No.

Description of Item(s)

(a)

Balance at End of

Quarter 1

(b)

Balance at End of

Quarter 2

(c)

Balance at End of

Quarter 3

(d)

Balance at End of

Year

(e)

1 Energy

2 Net Purchases (Account 555)

3 Net Purchases (Account 555.1)

4 Net Sales (Account 447)

5 Transmission Rights

6 Ancillary Services

7 Other Items (list separately)

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45 Total

FERC FORM 1/3-Q (REV 12-12) Page 397
Docket Nos. RM11-24-000 and AD10-13-000 - 112 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)

Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged 

and wheeled during the year. 

Line

No.

Item

(a)

MegaWatt Hours

(b)

Line 

No.

Item

(a)

MegaWatt 

Hours

(b)

1 SOURCES OF ENERGY DISPOSITION OF ENERGY

2 Generation (Excluding Station Use) Sales to Ultimate Consumers 

(Including Interdepartmental Sales)

3 Steam Requirements Sales for Resale (See 

Instruction 4, Page 311)

4 Nuclear Non-Requirements Sales for Resale 

(See Instruction 4, Page 311)

5 Hydro-Conventional Energy Furnished Without Charge

6 Hydro=Pumped Storage Energy Used by Company (Electric 

Department Only, Excluding Station 

Use) 

7 Other Total Energy Losses

8 Less Energy for Pumping TOTAL (Enter Total of Lines 22 

Through 27) MUST EQUAL LINE 20 

UNDER SOURCES 

9 Net Generation (Enter Total of Lines 3 through 8)

10 Purchases (other than for Energy Storage)

11 Purchases for Energy Storage

Power Exchanges

12 Received

13 Delivered

14 Net Exchanges (Line 12 minus Line 13)

15 Transmission for Others (Wheeling)

16 Received

17 Delivered

18 Net Transmission for Others (Line 16 minus line 

17)

19 Net Transmission for Others (Losses)

20 TOTAL (Enter Total of Lines 9, 10, 11, 14, 18 and 

19

FERC FORM NO. 1 (REV. 12-12) Page 401a
Docket Nos. RM11-24-000 and AD10-13-000 - 113 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ENERGY STORAGE OPERATIONS (Large Plants)

1. Large Plants are plants of 10,000 KW or more.

2. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location.

3. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage. 

4. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should 

include MWhs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services. 

5. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy. 

6. In column (k) report the MWHs sold. 

7. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income 

generating activity.

8. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage 

Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel 

costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power.

9. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, 

energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is 

to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property 

accounts listed. In addition, report the energy storage operation and maintenance expenses associated with each function.

Line

No.

Name of the Energy Storage Project

(a)

Functional 

Classification

(b)

Location of the Project

(c)

MWHs

(d)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35 TOTAL

 FERC FORM NO. 1/1-F (REV. 12-12) Page 414
Docket Nos. RM11-24-000 and AD10-13-000 - 114 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ENERGY STORAGE OPERATIONS (Large Plants) (Continued)

MWHs delivered to the grid to support MWHs Lost During Conversion, Storage and Discharge

of Energy

MWHs

Sold 

(k)

Revenues from the 

Sale of Stored 

Energy

(l)

Line

No.

Production

(e)

Transmission

(f) 

Distribution

(g)

Production

(h)

Transmission

(i)

Distribution

(j)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

 FERC FORM NO. 1/1-F (REV. 12-12) Page 415
Docket Nos. RM11-24-000 and AD10-13-000 - 115 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ENERGY STORAGE OPERATIONS (Large Plants) (Continued

Line

No.

Power Purchased for 

Storage Operations 

(555.1)

(Dollars)

(m)

Fuel Costs from 

associated fuel 

accounts for Storage 

Operations 

Associated with SelfGenerated Power 

(Dollars)

(n)

Other Costs 

Associated with SelfGenerated Power 

(Dollars)

(o)

Project Costs 

included in

(p)

Production

(Dollars)

(q)

Transmission

(Dollars)

(r)

Distribution

(Dollars)

(s)

1 Account 101

2 Account 103

3 Account 106

4 Account 107

5 Other

6

7

8

9 Total Project 

Costs

10

11

12 Storage 

Operation and 

Maintenance 

Costs by 

Function 

(Dollars)

13

14

15

16

17

18

19

20 Operation 

Expenses

21 Maintenance 

Expenses

22

23

24

25

26

27

28

29

30 Total

Operations 

and 

Maintenance 

Costs

 FERC FORM NO. 1/1-F (REV. 12-12) Page 416
Docket Nos. RM11-24-000 and AD10-13-000 - 116 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ENERGY STORAGE OPERATIONS (Small Plants)

1. Small Plants are plants less than 10,000 KW.

2 In columns (a), (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location.

3. In column (d), report project plant cost including but not exclusive of land and land rights, structures and improvements, energy storage equipment and any 

other costs associated with the energy storage project. 

4. In column (e), report operation expenses excluding fuel, (f), maintenance expenses, (g) fuel costs for storage operations and (h) cost of power 

purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an 

affiliated seller specify how the cost of the power was determined.

5. If any other expenses, report in column (i) and footnote the nature of the item(s). 

Line

No.

Name of the Energy Storage Project

(a)

Functional 

Classification

(b)

Location of the Project

(c)

Project 

Cost

(d)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36 TOTAL

 FERC FORM NO. 1/1-F (REV. 12-12) Page 418
Docket Nos. RM11-24-000 and AD10-13-000 - 117 -

Plant Operating Expenses 

Line

No. 

Operations

(Excluding Fuel

used in Storage 

Operations)

(e)

Maintenance

(f) 

Cost of fuel used 

in storage operations

(g)

Account No. 555.1, 

Power Purchased for 

Storage Operations

(h)

Other Expenses

(i)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

 FERC FORM NO. 1/1-F (REV. 12-12) Page 420

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

ENERGY STORAGE OPERATIONS (Small Plants)