144 FERC ¶ 61,056

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Parts 35, 101 and 141

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

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

New Electric Storage Technologies

(Issued July 18, 2013)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

SUMMARY: The Federal Energy Regulatory Commission (Commission) is revising its 

regulations to foster competition and transparency in ancillary services markets. The 

Commission is revising certain aspects of its current market-based rate regulations, 

ancillary services requirements under the pro forma open-access transmission tariff 

(OATT), and accounting and reporting requirements. Specifically, the Commission is 

revising Part 35 of its regulations to reflect reforms to its Avista policy governing the sale 

of ancillary services at market-based rates to public utility transmission providers. The 

Commission is also requiring each public utility transmission provider to add to its 

OATT Schedule 3 a statement that it will take into account the speed and accuracy of 

regulation resources in its determination of reserve requirements for Regulation and 

Frequency Response service, including as it reviews whether a self-supplying customer 

has made “alternative comparable arrangements” as required by the Schedule. The final 

rule also requires each public utility transmission provider to post certain Area Control 
Docket Nos. RM11-24-000 and AD10-13-000 - 2 -

Error data as described in the final rule. Finally, the Commission is revising the 

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

utilities and licensees and its forms, statements, and reports, contained in FERC Form 

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

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

No. 3-Q, Quarterly Financial Report of Electric Utilities, Licensees, and Natural Gas 

Companies, to better account for and report transactions associated with the use of energy 

storage devices in public utility operations.

EFFECTIVE DATE: This rule will become effective [insert date 120 days after 

publication in the FEDERAL REGISTER]. 

FOR FURTHER INFORMATION CONTACT:

Rahim Amerkhail (Technical Information)

Federal Energy Regulatory Commission, Office of Energy Policy and Innovation

888 First Street, NE

Washington, DC 20426

(202) 502-8266

Christopher Handy (Accounting Information)

Federal Energy Regulatory Commission, Office of Enforcement

888 First Street, NE

Washington, DC 20426

(202) 502-6496

Lina Naik (Legal Information)

Federal Energy Regulatory Commission, Office of the General Counsel

888 First Street, NE

Washington, DC 20426

(202) 502-8882

Eric Winterbauer (Legal Information)

Federal Energy Regulatory Commission, Office of the General Counsel

888 First Street, NE
Docket Nos. RM11-24-000 and AD10-13-000 - 3 -

Washington, D.C. 20426

(202) 502-8329

SUPPLEMENTARY INFORMATION
144 FERC ¶ 61,056

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Jon Wellinghoff, Chairman;

 Philip D. Moeller, John R. Norris,

Cheryl A. LaFleur, and Tony Clark.

Third-Party Provision of Ancillary Services; Accounting 

and Financial Reporting for New Electric Storage 

Technologies

Docket Nos. RM11-24-000

AD10-13-000

Order No. 784

FINAL RULE

(Issued July 18, 2013)

Table of Contents Paragraph Number

I. Background ............................................................................................................................6.

II. Discussion .............................................................................................................................12.

A. The Avista Policy.............................................................................................................12.

1. Use of Market Power Analyses ...................................................................................17.

a. Reliance on Existing Indicative Screens .................................................................20.

i. Application to Imbalance Ancillary Services ......................................................22.

ii. Application to Other Ancillary Services ...........................................................43.

b. Optional Market Power Screen ................................................................................62.

2. Alternative Mitigation .................................................................................................75.

a. Use of Price Caps .....................................................................................................76.

i. Single OATT Rate Cap Option ............................................................................77.

ii. Regional OATT Rate Cap Option .......................................................................86.

b. Competitive Solicitations.........................................................................................95.

B. Resource Speed and Accuracy in Determination of Regulation and Frequency 

Response Reserve Requirements ...........................................................................................102.

C. Accounting and Reporting for Energy Storage Operations .............................................122.

D. Other Issues......................................................................................................................188.

III. Summary of Compliance and Implementation....................................................................201.

IV. Information Collection Statement .......................................................................................207.

V. Environmental Analysis .......................................................................................................208.

VI. Regulatory Flexibility Act ..................................................................................................209.
Docket Nos. RM11-24-000 and AD10-13-000 - 2 -

VII. Document Availability.......................................................................................................210.

1. The Federal Energy Regulatory Commission (Commission) is revising its 

regulations to enhance competition and transparency in ancillary services markets. The 

Commission is revising certain aspects of its current market-based rate regulations, 

ancillary services requirements under the pro forma open-access transmission tariff 

(OATT), and accounting and reporting requirements. Specifically, the Commission is 

revising Part 35 of its regulations to reflect reforms to its Avista Corp.1policy governing 

the sale of ancillary services at market-based rates to public utility transmission 

providers. The Commission is also requiring each public utility transmission provider to 

add to its OATT Schedule 3 a statement that it will take into account the speed and 

accuracy of regulation resources in its determination of reserve requirements for 

Regulation and Frequency Response service, including as it reviews whether a selfsupplying customer has made “alternative comparable arrangements” as required by the 

Schedule. Each public utility transmission provider is also required to post certain Area 

Control Error data on the open access same-time information system (OASIS). Finally, 

the Commission is revising the accounting and reporting requirements under its Uniform 

System of Accounts for public utilities and licensees (USofA)2and its forms, statements, 

 

1

See 87 FERC ¶ 61,223 (Avista), order on reh’g, 89 FERC ¶ 61,136 (1999). 

2 Uniform System of Accounts Prescribed for Public Utilities and Licensees 

Subject to the Provisions of the Federal Power Act, 18 CFR Part 101 (2012).
Docket Nos. RM11-24-000 and AD10-13-000 - 3 -

and reports, contained in FERC Form No. 1 (Form No. 1), Annual Report of Major 

Electric Utilities, Licensees and Others,3FERC Form No. 1-F (Form No. 1-F), Annual 

Report for Nonmajor Public Utilities and Licensees,4and FERC Form No. 3-Q (Form 

No. 3-Q), Quarterly Financial Report of Electric Utilities, Licensees, and Natural Gas 

Companies,5to better account for and report transactions associated with the use of 

energy storage devices in public utility operations. 

2. First, the Commission reforms the Avista policy governing sales of certain 

ancillary services to a public utility purchasing the ancillary service to satisfy its own 

OATT requirements to offer ancillary services to its own customers. As noted in the 

Notice of Proposed Rulemaking,

6

there is a growing need for ancillary services to support 

grid functions in the face of potential changes in the portfolio of generation resources and 

a growing interest of transmission providers to have flexibility in meeting ancillary 

services needs.7 There is also interest in third-party provision of ancillary services and 

 

3

18 CFR 141.1 (2012).

4

18 CFR 141.2 (2012).

5

18 CFR 141.400 (2012).

6

Third-Party Provision of Ancillary Services; Accounting and Financial 

Reporting for New Electric Storage Technologies, Notice of Proposed Rulemaking, 

FERC Stats. & Regs. ¶ 32,690 (2012) (NOPR).

7

Integration of Variable Energy Resources, Order No. 764, FERC Stats. & Regs. 

¶ 32,331, order on reh’g, Order No. 764-A, 141 FERC ¶ 61,232 (2012); and Demand 

Response Compensation in Organized Wholesale Energy Markets, Order No. 745, FERC 

Stats. & Regs. ¶ 31,322, order on reh’g, Order No. 745-A, 137 FERC ¶ 61,215 (2011).
Docket Nos. RM11-24-000 and AD10-13-000 - 4 -

that interest may be unnecessarily frustrated by the Avista policy. Comments to the 

NOPR’s proposal to reconsider the Avista restrictions generally supported these concepts. 

As such, and as discussed further below, we conclude that elements of our existing 

market-based rate regulations can be modified in a manner that continues to limit the 

exercise of market power, while also enhancing the ability of third parties to compete for 

the sale of certain ancillary services.

3. Second, we adopt reforms to provide greater transparency with regard to reserve 

requirements for Regulation and Frequency Response. Under the requirements of the pro 

forma OATT, transmission customers may either purchase Regulation and Frequency 

Response service at cost-based rates from the public utility transmission provider 

pursuant to its OATT or self-supply the service, including through purchases from thirdparties.

8

 With regard to the notion of self-supply, the pro forma OATT Schedule 3 

merely states that the transmission customer must make alternative comparable 

arrangements to satisfy is Regulation and Frequency Response Service obligation. In 

particular, Schedule 3 provides no discussion of the meaning of the term “comparable” as 

 

8

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 31,716 (1996), order on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order 

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

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

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

535 U.S. 1 (2002); pro forma OATT, Original Sheet Nos. 20-21 and Schedule 3, Original 

Sheet No. 113.
Docket Nos. RM11-24-000 and AD10-13-000 - 5 -

it relates to reliance on resources with dispatch speed and accuracy characteristics that 

may differ from those used by the public utility transmission provider. Because the 

system must be operated reliably at all times, the customer may not decline the 

transmission provider’s offer of ancillary services unless it demonstrates that it has 

acquired comparable services from another source.9 In order to clarify the role of 

resource speed and accuracy in the determination of alternative comparable 

arrangements, in this Final Rule the Commission requires each public utility transmission 

provider to add to its OATT Schedule 3 a statement that it will take into account the 

speed and accuracy of regulation resources in its determination of reserve requirements 

for Regulation and Frequency Response service, including as it reviews whether a selfsupplying customer has made “alternative comparable arrangements” as required by the 

Schedule. This statement will also acknowledge that, upon request by the self-supplying 

customer, the public utility transmission provider will share with the customer its 

reasoning and any related data used to make the determination of whether the customer 

has made “alternative comparable arrangements.” To aid the transmission customer’s 

ability to make an “apples-to-apples” comparison of regulation resources, the final rule 

also requires each public utility transmission provider to post on OASIS historical oneminute and ten-minute Area Control Error data as described in the final rule for the most 

recent calendar year, and update this posting once per year. 

 

9 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,716.
Docket Nos. RM11-24-000 and AD10-13-000 - 6 -

4. With this information, a transmission customer will be in a position to demonstrate 

to the public utility transmission provider that the resource(s) it selects for self-supply are 

comparable to those of the public utility transmission provider. As such, these reforms 

are necessary to address the potential for undue discrimination against transmission 

customers choosing to self-supply Regulation and Frequency Response, including 

through purchases from third-parties. Acknowledging the speed and accuracy of the 

resources used to provide this service will help to ensure that self-supply requirements of 

the public utility transmission provider do not unduly discriminate by requiring 

customers to procure a different amount of regulation reserves than the particular speed 

and accuracy characteristics of the resources in question justify (i.e., to be comparable, a

customer self-supply arrangement that relies on slower, less accurate resources than those 

of the public utility transmission provider should probably involve a larger reserve 

requirement than would a purchase from the transmission provider, and vice versa). 

Moreover, as the Commission has previously stated, because most generation-based

ancillary services can be provided by many of the generators connected to the 

transmission system, some customers may be able to provide or procure such services 

more economically than the transmission provider can.10

 

10 Id. at 31,718. We note that customers could conceivably procure such services 

more economically either by paying much less per unit for a larger amount of slower, less 

accurate resources, or by paying somewhat more per unit for a smaller amount of faster, 

more accurate resources.
Docket Nos. RM11-24-000 and AD10-13-000 - 7 -

5. Finally, we adopt reforms to our accounting and reporting regulations to add new 

electric plant and operation and maintenance (O&M) expense accounts for energy storage 

devices. These reforms are necessary to accommodate the increasing availability of these 

new resources for use in public utility operations. These reforms are also necessary to 

ensure that the activities and costs of new energy storage operations are sufficiently 

transparent to allow effective oversight.

I. Background

6. The Commission has taken numerous steps 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.11 With regard to ancillary services, the Commission in Order No. 888 

delineated two categories of ancillary services: those that the transmission provider is 

 

11 See, e.g., Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,781; MarketBased Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by 

Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252, clarified, 121 FERC 

¶ 61,260 (2007), order on reh’g, Order No. 697-A, FERC Stats. & Regs. ¶ 31,268, 

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

¶ 31,285 (2008), order on reh’g, Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 (2009), 

order on reh’g, Order No. 697-D, FERC Stats. & Regs. ¶ 31,305 (2010), aff’d sub nom. 

Montana Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011), cert. denied sub 

nom. Pub. Citizen, Inc. v. FERC, 133 S. Ct. 26 (2012); Preventing Undue Discrimination 

and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, 

order on reh’g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, 

Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 

FERC ¶ 61,228 (2009), order on reh’g, Order No. 890-D, 129 FERC ¶ 61,126 (2009); 

Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, 

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

& Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).
Docket Nos. RM11-24-000 and AD10-13-000 - 8 -

required to provide to all of its basic transmission customers12 and those that the 

transmission provider is only required to offer to provide to transmission customers 

serving load in the transmission provider’s control area.13 With respect to the second 

category the Commission reasoned that the transmission provider is not always uniquely 

qualified to provide the services and customers may be able to more cost-effectively selfsupply them or procure them from other entities. The Commission contemplated that 

third parties (i.e., parties other than a transmission provider supplying ancillary services 

pursuant to its OATT obligation) could provide ancillary services on other than a cost-ofservice basis if such pricing was supported, on a case-by-case basis, by analyses that 

demonstrated that the seller lacks market power in the relevant product market.14 Later, 

in Ocean Vista Power Generation, L.L.C.,

15 the Commission provided guidance 

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

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

 

12 The first category consists of Scheduling, System Control and Dispatch service 

and Reactive Supply and Voltage Control from Generation Sources service.

13 The second category consists of Regulation and Frequency Response service, 

Energy Imbalance service, Operating Reserve-Spinning service, and Operating ReserveSupplemental service. Order No. 890 later added an additional OATT ancillary service 

to this category: Generator Imbalance service. See Order No. 890, FERC Stats. & Regs. 

¶ 31,241 at P 85.

14 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,720-21.

15 82 FERC ¶ 61,114, at 61,406-07 (1998) (Ocean Vista).
Docket Nos. RM11-24-000 and AD10-13-000 - 9 -

the nature and characteristics of generation capable of supplying each service, and that 

the study should develop market shares for each service.

7. The Commission subsequently acknowledged in Avista16 that data limitations can 

impair the ability of sellers to perform a market power study for ancillary services 

consistent with the requirements of Ocean Vista. The Commission therefore adopted a 

policy allowing third-party ancillary service providers that could not perform a market 

power study to sell certain ancillary services at market-based rates with certain 

restrictions.17 In so doing, the Commission reasoned that the backstop of cost-based 

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

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

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

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

of potential third-party market power in three situations: (1) sales to a regional 

transmission organization (RTO) or an independent system operator (ISO), which has no 

 

16 Avista, 87 FERC at 61,882.

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

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

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

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

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

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

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

operators can provide this ancillary service, it does not lend itself to competitive supply.
Docket Nos. RM11-24-000 and AD10-13-000 - 10 -

ability to self-supply ancillary services but instead depends on third parties;18 (2) to 

address affiliate abuse concerns, sales to a traditional, franchised public utility affiliated 

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

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

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

to offer ancillary services to its own customers.19 Therefore, the Commission’s Avista

policy has allowed third-party suppliers to sell certain ancillary services at market-based 

rates without showing a lack of market power, except under these three circumstances. 

8. In its ongoing effort to enhance competitive markets as a means to ensure just and 

reasonable rates, including those for ancillary services, the Commission has continued to 

evaluate its Avista policy, including, with particular regard to this proceeding, the 

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

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

services to its own customers. The Commission’s concern has been to ensure that the 

cost-based OATT ancillary service rates of public utilities remain a viable backstop or 

alternative that transmission customers can rely upon instead of the market-based sales 

from third parties who have not been shown to lack market power. The Commission has 

 

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

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

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

n.1194 and P 1069. 

19 Avista, 87 FERC ¶ 61,223 at n.12.
Docket Nos. RM11-24-000 and AD10-13-000 - 11 -

reasoned that, if such third-party sellers were permitted to sell to public utilities seeking 

to meet their OATT ancillary service obligations, the public utility’s ability to seek 

recovery of such purchase costs in OATT rates might lead to increases in those OATT 

ancillary service rates that may reflect the exercise of market power thus reducing the 

rates’ ability to serve as an effective alternative to purchases from a third-party seller 

unable to show lack of market power. This would undermine the effectiveness of the 

mitigation measure that the Commission relied upon in Avista to relax the requirement 

for a market power analysis.20 

9. However, as the record in this proceeding demonstrates, the restriction on sales of 

ancillary services at market-based rates to a public utility for purposes of satisfying its 

OATT requirements has proven to be an unreasonable barrier to entry, unnecessarily 

restricting access to potential suppliers. In the NOPR, the Commission proposed to 

address this problem by reforming the Avista restrictions, both by modifying the showing 

an entity must make to establish that it lacks market power and by establishing market 

power mitigation options in the absence of such a showing. 

10. Building off the Commission’s action in Order No. 755, which found that 

accounting for a given resource’s speed and accuracy can help ensure just and reasonable 

 

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

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

charged by the third-party supplier is disciplined by the obligation of the transmission 

provider to offer these services under cost-based rates. This discipline would be thwarted 

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

mandatory service obligation.”).
Docket Nos. RM11-24-000 and AD10-13-000 - 12 -

rates and prevent against undue discrimination, in the NOPR, the Commission also 

proposed to require each public utility transmission provider to include provisions in its 

OATT explaining how it will determine regulation service reserve requirements for 

transmission customers, including those that choose to self-supply regulation service, in a 

manner that takes into account the speed and accuracy of resources used. 

11. Finally, the Commission proposed to modify its accounting regulations to increase 

transparency for energy storage facilities. While the Commission’s accounting and 

reporting requirements associated with the USofA do not dictate the ratemaking decisions 

of this Commission or State Commissions, these accounting and reporting requirements 

nevertheless support the rate oversight needs of both this Commission and State 

Commissions. This information is important in developing and monitoring rates, making 

policy decisions, compliance and enforcement initiatives, and informing the Commission 

and the public about the activities of entities that are subject to these accounting and 

reporting requirements.21 

II. Discussion

A. The Avista Policy

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

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

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

 

21 Applicants for market-based rate authority that do not sell under cost-based rates 

frequently seek and typically are granted waiver of many or all of these requirements.
Docket Nos. RM11-24-000 and AD10-13-000 - 13 -

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

satisfy its own OATT requirements to offer ancillary services to its own customers. In 

order to overcome this restriction, a potential seller must provide a market power study 

demonstrating a lack of market power for the particular ancillary service in the particular 

geographic market. Based on the record before us, the Commission adopts a number of 

the reforms to the ancillary services pricing policy proposed in the NOPR and in some 

instances adopts a number of modifications to those reforms based on the comments 

received in response to the NOPR. 

13. Specifically, this Final Rule allows a resource with market-based rate authority for 

sales of energy and capacity to sell imbalance services at market-based rates to a public 

utility transmission provider in the same balancing authority area, or to a public utility 

transmission provider in a different balancing authority area, if those areas have 

implemented intra-hour scheduling for transmission service. In addition, upon 

consideration of the comments to the NOPR, this Final Rule also allows a resource with 

market-based rate authority for sales of energy and capacity to sell operating reserve 

services at market-based rates to a public utility transmission provider in the same 

balancing authority area, or to a public utility transmission provider in a different 

balancing authority area, if those areas have implemented intra-hour scheduling for 

transmission service that supports the delivery of operating reserve resources from one 

balancing authority area to another. As a result, the only remaining limitation on thirdparty market-based sales of ancillary services is on sales of Reactive Supply and Voltage 

Control service and Regulation and Frequency Response service to a public utility that is 
Docket Nos. RM11-24-000 and AD10-13-000 - 14 -

purchasing ancillary services to satisfy its own OATT requirements absent a showing of 

lack of market power or adequate mitigation of potential market power. In that regard, 

third-party sales of Reactive Supply and Voltage Control service and Regulation and 

Frequency Response service to public utility transmission providers will be permitted at 

rates not to exceed the buying public utility transmission provider’s OATT rate for the 

same service. Further, to the extent a transmission provider chooses to procure either 

Reactive Supply and Voltage Control service or Regulation and Frequency Response 

service through a competitive solicitation that meets the requirements of this Final Rule, 

third-party sellers of these services may sell at market-based rates. 

14. While the record in this proceeding was insufficient for the Commission to relieve 

the restrictions for Reactive Supply and Voltage Control service and Regulation and 

Frequency Response service in the same manner as Imbalance and Operating reserves, 

we remain interested in exploring the technical, economic and market issues concerning 

the provision of Reactive Supply and Voltage Control service and Regulation and 

Frequency Response service. As such, the Commission intends to gather further 

information regarding the provision of Reactive Supply and Voltage Control service and 

Regulation and Frequency Response service in a separate, new proceeding.

15. Thus, while we decline to adopt some of the reforms proposed in the NOPR based 

on the record in this proceeding, we expect that this Final Rule substantially enhances the 

overall opportunities for third-parties to compete to make sales of ancillary services while 

continuing to limit the exercise of market power. 
Docket Nos. RM11-24-000 and AD10-13-000 - 15 -

16. We will first discuss the market power analyses used to establish authority to sell 

at market-based rates, followed by a discussion of alternative cost-based mitigation in the 

event a market participant cannot show it lacks market power for a specific product or 

service. 

1. Use of Market Power Analyses 

17. The Commission analyzes horizontal market power22 for sales of energy and 

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

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

otherwise be considered for market-based rate authority.23 The wholesale market share 

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

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

controlled by the seller, as compared to the uncommitted capacity of the entire market.24 

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

passes the wholesale market share screen.25 The pivotal supplier screen evaluates the 

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

 

22 18 CFR 35.37(b) (2012). 

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

35.37(b), (c)(1) (2012).

24 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 43. Uncommitted capacity is 

determined by adding the total nameplate or seasonal capacity of generation owned or 

controlled through contract and firm purchases, less operating reserves, native load 

commitments and long-term firm sales. Id. P 38.

25 Id. PP 43-44, 80, 89. 
Docket Nos. RM11-24-000 and AD10-13-000 - 16 -

capacity at the time of annual peak demand in the relevant market.26 A seller satisfies the 

pivotal supplier screen if its uncommitted capacity is less than the net uncommitted 

supply in the relevant market.27 

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

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

with respect to sales of energy or capacity; failing either screen creates a rebuttable 

presumption that the seller possesses horizontal market power for such sales.

28

 A seller 

that fails one of the screens may present evidence, such as a delivered price test (DPT), to 

rebut the presumption of horizontal market power.29 In the alternative, a seller may 

accept the presumption of horizontal market power and adopt some form of cost-based 

mitigation.30 

 

26 18 CFR 35.37(c)(1) (2012). 

27 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 42. 

28 18 CFR 35.37(c)(1) (2012). 

29 18 CFR 35.37(c)(2) (2012). For purposes of rebutting the presumption of 

horizontal market power, sellers may use the results of the DPT to refine the default 

relevant geographic market used to perform pivotal supplier and market share analyses 

and market concentration analyses using the Herfindahl-Hirschman Index (HHI). The 

HHI is a widely accepted measure of market concentration, calculated by squaring the 

market share of each firm competing in the market and summing the results. The 

Commission has stated that a showing of an HHI less than 2,500 in the relevant market 

for all season/load periods for sellers that have also shown that they are not pivotal and 

do not possess a market share of 20 percent or greater in any of the season/load periods 

would constitute a showing of a lack of horizontal market power, absent compelling 

contrary evidence from intervenors. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 

P 111.

30 18 CFR 35.37(c)(3) (2012). 
Docket Nos. RM11-24-000 and AD10-13-000 - 17 -

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

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

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

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

default relevant geographic market for sales of energy and capacity.31 In particular, the 

Commission will generally use a seller’s balancing authority area plus first-tier markets,32

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

sales of energy and capacity, the product definitions are well understood: the relevant 

geographic market is generally the default market described above; and, the uncommitted 

generation supply is generally identified as all such supply located within the seller’s 

balancing authority area, plus potential uncommitted imports, as determined largely by 

available transmission capacity in the form of simultaneous import limits.33 Except in the 

circumstances set forth in Avista, entities seeking to sell ancillary services at marketbased rates have been required to provide market power analyses that address the nature 

and characteristics of each ancillary service, as well as the nature and characteristics of 

 

31 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 15.

32 First-tier markets are those markets directly interconnected to the seller’s 

balancing authority area. See, e.g., Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 

P 232.

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

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

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

market when performing market power analyses.
Docket Nos. RM11-24-000 and AD10-13-000 - 18 -

generation capable of supplying each service.

34 This requirement was based on an 

assumption that such characteristics might differ from those related to sales of energy and 

capacity. 

a. Reliance on Existing Indicative Screens

20. In the NOPR, the Commission analyzed whether passage of the existing marketbased rate screens for sales of energy and capacity can adequately demonstrate lack of 

market power for sales of ancillary services, based on the relevant characteristics of 

resources capable of providing each ancillary service. Based on this analysis, the 

Commission proposed that only the two imbalance ancillary services (Energy Imbalance 

and Generator Imbalance), and no other ancillary services, could be encompassed by the 

existing market-based rate screens.35 The Commission sought comment on both this 

analysis and the resulting proposal.36

21. As discussed in more detail below, commenters addressed both the Commission’s 

ancillary service-by-ancillary service analysis of this issue, and the proposal to apply the 

existing market power screens to only the imbalance ancillary services.

 

34 See, Ocean Vista, 82 FERC ¶ 61,114, at 61,406-07 (1998).

35 NOPR, FERC Stats. & Regs. ¶ 32,690 at PP 18-24.

36 Id. P 24.
Docket Nos. RM11-24-000 and AD10-13-000 - 19 -

i. Application to Imbalance Ancillary Services 

Commission Proposal

22. In the NOPR, the Commission stated that resources capable of providing Energy 

Imbalance and Generator Imbalance do not appear to require any different technical 

equipment or suffer from any different geographical limitations compared to resources 

that provide energy or capacity. As a result, the Commission proposed that sellers 

passing existing market power analyses should be permitted to sell not only energy and 

capacity in the relevant geographic market(s), but also Energy Imbalance and Generator 

Imbalance services at market-based rates. The Commission sought comments on, among 

other things, any unique technical requirements or limitations that might apply to the 

provision of the imbalance ancillary services that might impact the Commission’s 

proposal to find that passage of the existing market power screens also indicates a lack of 

market power for imbalance services.37

Comments

23. The majority of commenters support the Commission’s proposal. AWEA, 

Beacon, California Storage Alliance, EEI, Electricity Consumers, EPSA, ESA, Iberdrola, 

Hydro Association, Public Interest Organizations, Powerex, Solar Energy Association, 

Shell Energy, Southern California Edison, and WSPP support the NOPR proposal to 

revise the Commission’s regulations governing market-based rate authorizations to 

 

37 Id. PP 19-20. 
Docket Nos. RM11-24-000 and AD10-13-000 - 20 -

provide that sellers passing existing market-based rate analyses in a given geographic 

market should be granted a rebuttable presumption that they lack horizontal market 

power for sales of Energy Imbalance and Generator Imbalance ancillary services in that 

market. 

24. ESA, Electricity Consumers, Beacon, and EEI, among others, agree that there are 

no special technical requirements or other limitations that apply to the provision of the 

Energy Imbalance or Generator Imbalance ancillary services.38 Electricity Consumers 

and WSPP, among others, argue that the proposed revisions should reduce barriers to 

ancillary service providers and increase the supply of needed ancillary services. WSPP 

agrees that the proposal would enable additional sellers of balancing energy to transact 

with public utility transmission providers in both bilateral markets or a multi-lateral 

balancing market, and states that it would likely foster sales of balancing energy even 

outside of the transmission provider market. AWEA contends that the Commission’s 

proposed reforms strike the appropriate balance between reducing barriers to entry and 

protecting against market power. 

25. WSPP and Powerex, with Iberdrola concurring by reference, urge the Commission 

to clarify that this proposal includes the capacity associated with balancing energy sales, 

not just the energy.39 WSPP states that without the underlying capacity, sales of 

 

38 ESA Comments at 6; Beacon Comments at 5; Electricity Consumers Comments 

at 3; and EEI Comments at 9.

39 WSPP Comments at 6; and Powerex Comments at 9-10.
Docket Nos. RM11-24-000 and AD10-13-000 - 21 -

balancing energy could have no firmness and would be of little value in the market, in 

particular the bilateral market. Further, WSPP contends that the likely market for 

balancing energy would not differentiate energy and capacity products by OATT 

Schedules. Rather, sellers would sell “flexible capacity” capable of fulfilling multiple 

OATT Schedules and operators would look to flexible capacity to support various system 

stabilizing functions to which the OATT Schedules refer. Thus, WSPP contends that the 

market would be more efficient if the capacity and energy required to provide OATT 

services are not required to be unbundled when the natural market for supply would be a 

bundled “flexible capacity” product.40 

26. Solar Energy Association states conceptual support for the proposal, but argues 

that sellers may have market power in certain ancillary services markets even if not in 

energy or capacity markets, and urges the Commission to police markets that are created 

due to the adoption of a rebuttable presumption of lack of market power.41 

27. Two commenters express concern with the NOPR proposal. TAPS objects to the 

NOPR’s preliminary finding that any available unit in a given geographic market is 

capable of providing energy that helps address imbalances in that market. TAPS 

contends that significant technical limitations limit the resources that can provide 

imbalance services absent special arrangements like pseudo-ties, and therefore the first 

 

40 WSPP Comments at 7.

41 Solar Energy Association Comments at 4.
Docket Nos. RM11-24-000 and AD10-13-000 - 22 -

tier resources included in the horizontal market power screen are not generally available 

to provide intra-hour imbalance service. TAPS asserts that Order No. 890-A supports 

this contention by allegedly finding “that generation outside the control area can provide 

imbalance service when pseudo-tied and thus subject to within-area dispatch control.”42 

TAPS further states that outside organized markets, generators capable of providing 

imbalance service must have a special relationship with the control area operator in order 

to supply changing within-the-hour energy needs, without the constraints of hourly 

transmission scheduling requirements and that even the recently adopted 15-minute 

scheduling requirement is insufficient, especially when combined with the need to 

schedule 20 minutes in advance.43

28. TAPS asserts that, in non-RTO regions, imbalance service is typically provided by 

the energy associated with regulation and operating reserves, and thus resources capable 

of providing imbalance services would necessarily be subject to the same technical 

requirements as the NOPR described for regulation and operating reserves.44 TAPS 

supports this assertion by claiming that Order No. 890 found that “demand costs of 

providing imbalance service are already being provided under Schedule 3, 5, and 6 

 

42 TAPS Comments at 11-12.

43 Id. at 11-13.

44 Id. at 12-13.
Docket Nos. RM11-24-000 and AD10-13-000 - 23 -

charges [i.e., Regulation and Frequency Response Service, Operating Reserve-Spinning 

Reserve Services, and Operating Reserve Supplemental Reserve Services].”45 

29. TAPS further rejects the Commission’s assertion in the NOPR that this proposal is 

consistent with the decision in Order No. 890-A to base cost-based imbalance charges in 

the OATT on the incremental cost of the last 10 MW dispatched by the transmission 

provider for any purpose, without imposing any requirement that this last 10 MW be 

based on resources with any particular capabilities.46 TAPS contends that the pricing of 

OATT imbalance service does not demonstrate the absence of the alleged restrictions 

described above on the supply of intra-hour energy that allows transmission providers to 

provide energy imbalance service. 

30. Morgan Stanley contends that the existing market power screens are flawed even 

in their application to energy and capacity products and thus should not be applied to 

additional products. Morgan Stanley argues that the existing market power screens in 

some cases fail to assess the full import capability into a given geographic market, and 

thus the true market size. Morgan Stanley ultimately argues that a revised market power 

screen “should include any transmission located outside of the relevant market area, but 

which is interconnected and over which there is transfer capacity.”47 However, Morgan 

 

45 Id. at 12 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 690).

46 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 19 (citing Order No. 890-A, FERC 

Stats. & Regs. ¶ 31,261 at P 309).

47 Morgan Stanley Comments at 2-5.
Docket Nos. RM11-24-000 and AD10-13-000 - 24 -

Stanley does not state opposition to the idea that a lack of market power in energy and 

capacity can justify an assumption of equivalent lack of market power in Energy 

Imbalance and Generator Imbalance services.

Commission Determination

31. The Commission will adopt its proposal with modification. The Commission will 

allow third-party sellers passing existing market power screens to sell Energy Imbalance 

and Generator Imbalance services at market-based rates to a public utility transmission 

provider within the same balancing authority area, or to a public utility transmission 

provider in a different balancing authority area, if those areas have implemented intrahour scheduling for transmission service.48

 The Commission continues to believe that 

there are no unique technical requirements or limitations that apply to a resource’s 

provision of Energy Imbalance or Generator Imbalance services. However, the 

Commission agrees with TAPS that the delivery of Energy Imbalance and Generator 

Imbalance services may be limited by hourly transmission scheduling practices in place 

within certain regions and, as such, refines the NOPR proposal as discussed below. 

32. Energy Imbalance and Generator Imbalance services are a subset of a broader set 

of ancillary services offered by a public utility transmission provider to manage system 

conditions and ensure reliable transmission service. Energy Imbalance and Generator 

Imbalance services involve the balancing of differences between scheduled and actual 

 

48 We note that sales of Energy Imbalance and Generator Imbalance services to 

entities other than a public utility transmission provider remain authorized under Avista.
Docket Nos. RM11-24-000 and AD10-13-000 - 25 -

delivery of energy or output of generation over an hour.49 In comparison, Regulation and 

Frequency Response service involves the matching of resources to load in a shorter 

timeframe, requiring automated dispatch at four- or five-second intervals.50 As a result, 

resources used to provide Regulation and Frequency Response service must be capable of 

balancing moment-to-moment fluctuations, whereas resources used to provide Energy 

and Generator Imbalance can respond at longer time frames within the hour.

33. In practice, public utility transmission providers often have a portfolio of 

resources, some owned and some purchased from third-parties, from which they provide 

capacity, energy, and ancillary services. This portfolio typically includes resources with 

automatic generation control (AGC) equipment capable of handling both moment-bymoment frequency adjustments and longer duration imbalance needs, as well as other 

capacity and energy resources that may only be capable of addressing longer duration 

imbalance needs because they are not equipped with AGC. These longer duration 

resources may include block purchases from third parties that are dispatched or otherwise 

scheduled at varying timeframes. The relative amount of AGC-controlled and other 

 

49 See pro forma OATT, Schedules 4 and 9. Under the pro forma OATT, 

imbalances are calculated and charged on an hourly basis. See Order No. 890, FERC 

Stats. & Regs. ¶ 31,241 at P 722; Order No. 890-A, FERC Stats. & Regs. ¶ 61,297 at 

P 325 & n.117; see also Order No. 764, FERC Stats. & Regs. ¶ 32,331 at P 104. Energy 

Imbalance and Generator Imbalance services also may be self-supplied by a transmission 

customer.

50 See, e.g., Pro Forma OATT, Schedule 3 Regulation and Frequency Response 

Service – “Regulation and Frequency Response Service is necessary to provide for the 

continuous balancing of resources (generation and interchange) with load . . ..”
Docket Nos. RM11-24-000 and AD10-13-000 - 26 -

resources used by a public utility transmission provider for intra-hour balancing will 

depend on the resources available and the public utility transmission provider’s operating 

practices. 

34. In the NOPR, the Commission did not separately discuss this range of resources 

and, instead, preliminarily concluded that there are no unique technical requirements or 

limitations that distinguish the resources capable of providing energy and capacity from 

those capable of providing imbalance services. The majority of commenters agree with 

the Commission’s preliminary conclusion, arguing that the set of resources available to 

follow imbalances over an hour is the same set of resources capable of providing energy 

and capacity. However, TAPS disagrees, arguing that the set of resources capable of 

providing imbalance services must have a special relationship with the control area 

operator in order to supply changing within-the-hour energy needs. 

35. We understand TAPS’ argument to be that resources used to provide imbalance 

service must be able to respond to a dynamic four- or five-second signal, which might 

require special arrangements in order to permit imbalance sales outside of the resource’s 

home balancing authority area such that even the ability to submit transmission schedules 

on a 15-minute basis would be insufficient to provide intra-hour imbalance energy.51 We 

agree that some of the public utility transmission provider’s energy imbalance needs are 

addressed by resources that manage the moment-by-moment difference between load and 

 

51 TAPS Comments at 13.
Docket Nos. RM11-24-000 and AD10-13-000 - 27 -

resources. We also agree that imbalance service would generally require deliveries on 

intervals shorter than the current hour. But we do not agree, as explained more fully 

below, that imbalance services require dynamic dispatch or more sophisticated delivery 

mechanisms than intra-hour transmission scheduling. 

36. Under the pro forma OATT, imbalances are calculated on an hourly basis.52 As a 

result, any energy deliveries within the hour can be used by a public utility transmission 

provider (or by a transmission customer) to manage imbalances across the hour. That is, 

energy deliveries within the hour can be included in the portfolio of resources used to 

follow imbalance trends across the hour, similar to a public utility transmission 

provider’s decision to redispatch its own internal resources within the hour. While it is 

true, as TAPS states, that dynamically dispatched resources capable of providing 

regulation also would be capable of providing imbalance services, it does not follow that 

resources using intra-hour transmission schedules are incapable of providing imbalance 

services. As noted above, imbalance service can be provided from a collection of 

resources so long as they are deliverable within the hour.53

 

52 See Order No. 890, FERC Stats. & Regs. at P 722, order on reh’g, Order 

No. 890-A, FERC Stats. & Regs. ¶ 61,297 at P 325 & n.117; see also Order No. 764, 

FERC Stats. & Regs. ¶ 32,331 at P 104.

53 The Commission acknowledges that energy purchases scheduled on an hourly 

basis might enable a public utility transmission provider to use other resources to provide 

imbalance or other ancillary services more efficiently or precisely. Such hourly sales of 

energy would not be an indirect sale of ancillary services within the meaning of Avista. 
Docket Nos. RM11-24-000 and AD10-13-000 - 28 -

37. The question before the Commission here is whether the set of resources 

considered available to provide energy and capacity in a market power analysis is 

sufficiently similar to the set of resources capable of providing imbalance services. 

Based on the record before us in which numerous commenters agree that the resources 

are sufficiently similar and given that intra-hour transmission schedules are currently 

being offered by a number of public utility transmission providers, and must be offered 

by all public utility transmission providers under Order No. 764 on or before November 

12, 2013,54 the Commission finds it appropriate at this time to revise the Avista restriction 

to better reflect current operational realities.

38. With regard to TAPS’ additional comments in support of its basic argument, as 

stated above, just because a public utility transmission provider may have chosen to rely 

on the energy associated with regulation or operating reserves to meet imbalances, it does 

not follow that those are the only resources capable of providing imbalance services. 

Moreover, TAPS’ reference to a portion of a passage from Order No. 890 referring to 

demand costs of providing imbalance energy being recoverable through regulation 

(Schedule 3) and operating reserve (Schedules 5 and 6) services is not dispositive here. 

The rate mechanisms used by a public utility transmission provider to recover the cost of 

 

54 In order to comply with Order No. 764, public utility transmission providers 

must allow transmission customers to modify existing schedules as well as create new 

transmission schedules at intervals not to exceed 15 minutes, on or before November 12, 

2013. Order No. 764, FERC Stats. & Regs. ¶ 32,331 at P 91, order on reh’g, Order 764-

A, 141 FERC ¶ 61,232.
Docket Nos. RM11-24-000 and AD10-13-000 - 29 -

capacity associated with providing Energy Imbalance or Generator Imbalance service do 

not precisely reflect the technical capabilities of resources available to provide the 

imbalance services. There is no requirement, in past Commission pronouncements or 

otherwise, that imbalance services be provided only from resources capable of providing 

regulation or operating reserves. Indeed, TAPS criticizes the NOPR for asserting the 

Commission’s proposal was consistent with the decision in Order No. 890-A to base costbased imbalance charges on the incremental cost of the last 10 MW dispatched by the 

transmission provider for any purpose, without imposing any requirement that this last 

10 MW be based on resources with any particular capabilities.55 We agree with TAPS 

that the pricing of OATT imbalance services does not necessarily determine the technical 

capabilities of resources available to provide those services and reject the NOPR’s 

assertion in this regard. Similarly, we find that the pricing of regulation and operating 

reserve services, whether through Schedules 3, 5, 6 or some other mechanism (such as 

generator regulation service), do not necessarily determine the technical capabilities of 

resources available to provide imbalance services.

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

can provide imbalance service when pseudo-tied and thus subject to within-area 

 

55 See NOPR, FERC Stats. & Regs. ¶ 32,690 at P 19 (citing Order No. 890-A, 

FERC Stats. & Regs. ¶ 31,261 at P 309).
Docket Nos. RM11-24-000 and AD10-13-000 - 30 -

dispatch.56 The cited passage of Order No. 890-A, however, states that a pseudo-tie 

arrangement causes a control area to “assum[e] responsibility for ensuring that the load is 

properly balanced moment-to-moment, for planning for the load, and for providing 

various other ancillary services including energy or generator balancing service.” The 

Commission made no determination in that passage as to the universe of resources 

capable, or incapable, of providing imbalance services. Nevertheless, the Commission 

acknowledges that some public utility transmission providers may choose not to purchase 

imbalance service from resources that cannot also be dynamically dispatched. While that 

may inform the relative ability of a resource to find a buyer for its service, it does not 

define the set of resources from which imbalance services are available, which is the 

relevant question for market power analyses. 

40. We also find the opposing arguments of Morgan Stanley to be beyond the scope of 

this proceeding. Morgan Stanley does not appear to object to the use of the same market 

power screens for energy, capacity and imbalance services. Rather, Morgan Stanley 

argues that the existing indicative screens should be reformulated to include greater 

transmission imports than are currently assumed. Arguments as to the make-up of the 

existing market power screens are beyond the scope of this proceeding. The question 

before us in this proceeding is whether the resources in a given geographic market 

capable of providing imbalance ancillary services are sufficiently similar to the resources 

 

56 TAPS Comments at 12 (citing Order No. 890-A, FERC Stats. & Regs. ¶ 31,261

at P 631).
Docket Nos. RM11-24-000 and AD10-13-000 - 31 -

capable of providing energy and capacity that the same market power analysis can apply 

to both sets of products. Moreover, the Commission already permits applicants to 

demonstrate that the relevant geographic market is larger or smaller than that default.57

41. Accordingly, this Final Rule establishes that sellers found to lack market power in 

a geographic market, and which are granted market-based rate authority to make sales of 

energy and capacity, will also be granted market-based rate authority for sales of Energy 

Imbalance and Generator Imbalance services to public utility transmission providers

within the same balancing authority area, or to public utility transmission providers in 

different balancing authority areas, if those areas allow transmission customers to modify 

or create transmission schedules within the hour. Because, as explained above, such 

scheduling practices enable the delivery of within-hour imbalance services from one 

balancing authority area to another, their use ensures that the first-tier resources included 

in the existing market power screens can compete with resources in the home balancing 

authority area, and thus that the existing market power screens can be applied to 

imbalance services without modification. This finding applies both to sellers that 

currently have a market-based rate tariff on file and applicants seeking market-based rate 

authority. For administrative convenience, we make this change to the Commission’s 

ancillary services pricing policy effective as of the effective date of this Final Rule 

(120 days after publication in the Federal Register), which will result in these changes 

 

57 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 268.
Docket Nos. RM11-24-000 and AD10-13-000 - 32 -

becoming effective after November 12, 2013, the date by which all public utility 

transmission providers must offer intra-hour transmission scheduling. As noted above, 

we acknowledge that some transmission providers already offer intra-hour scheduling. 

However, rather than performing a transmission provider-by-transmission provider 

review of current scheduling practices in this rulemaking, the Commission will defer 

implementation of this change to our ancillary services pricing policy until after the 

effectiveness of the intra-hour scheduling requirements of Order No. 764, by which time 

all public utility transmission providers must offer intra-hour scheduling. Thus, as of the 

effective date, all sellers that have a market-based rate tariff on file as of that date may 

begin making third-party sales of Energy Imbalance and Generator Imbalance services at 

market-based rates to a public utility transmission provider that is purchasing Energy 

Imbalance and Generator Imbalance services to satisfy its own open access transmission 

tariff requirements to offer ancillary services to its own customers, without having to 

make a separate showing to the Commission.

42. In response to WSPP, we clarify that this authorization to undertake sales at 

market-based rates may include both the capacity and the energy associated with 

providing Energy Imbalance and Generator Imbalance services. Imbalance services are 

products designed to address differences between scheduled and actual deliveries and 

withdrawals of energy. As such, they can only be provided by ensuring the availability 
Docket Nos. RM11-24-000 and AD10-13-000 - 33 -

of capacity and then increasing or decreasing the energy output from that capacity as 

necessary to address these differences.58 

ii. Application to Other Ancillary Services 

Commission Proposal

43. In the NOPR, the Commission proposed to allow the existing market-based rate 

screens to be applied to Energy Imbalance and Generator Imbalance services, but sought 

comment on whether the characteristics of resources used to provide the other ancillary 

services would necessitate a market power analysis based on a different geographic 

market or different set of resources as compared to those analyzed to determine market 

power for sales of energy and capacity.59

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

the NOPR discussed the technical considerations, such as minimum ramp and start-up 

rates for off-line resources and the ability for extended operation below fully loaded set

point for online resources, that seemed to indicate that fewer resources would be capable 

of providing these ancillary services as compared to the set of resources capable of 

providing energy or capacity. With regard to Reactive Supply and Voltage Control from 

Generation Sources, the NOPR discussed the technical and geographic considerations 

that generally limit the resources capable of providing this ancillary service as compared 

 

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

59 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 24.
Docket Nos. RM11-24-000 and AD10-13-000 - 34 -

with the broader set of resources capable of providing energy or capacity. With regard to 

Regulation and Frequency Response, the Commission discussed the technical 

requirements, such as automatic generation control (AGC) equipment, that limit the set of 

resources capable of supplying this ancillary service.60 

Comments

45. A number of commenters argue for application of the existing market power 

screens to Operating Reserve-Spinning and Operating Reserve-Supplemental.61 EPSA 

argues that operating reserves are merely derivatives of a resource’s ability to generate 

energy.

62

46. WSPP argues that the same considerations that led the Commission to believe that 

the rebuttable presumption should be extended to the imbalance ancillary services also 

apply to the operating reserve ancillary services. WSPP further asserts that all of these 

ancillary services are widely deliverable and that all generators capable of being 

redispatched to higher or lower set-points within a scheduling window are capable of 

providing these ancillary services.

63

 

 

60 Id. PP 22-23.

61 EPSA Comments at 6, WSPP Comments at 8 (with Iberdrola supporting by 

reference), EEI Comments at 3 and 10, Western Group Comments at 3-4, Hydro 

Association Comments at 7, and Powerex Comments at 7 and 13.

62 EPSA Comments at 6.

63 WSPP Comments at 8. Iberdrola supports these WSPP comments by reference.
Docket Nos. RM11-24-000 and AD10-13-000 - 35 -

47. EEI argues that except for variable energy resources, essentially the same set of 

resources evaluated as competing supply under the existing market power screens possess 

the required technical capabilities to provide operating reserves.64 Western Group makes 

a similar argument, asserting that products in Schedules 3, 5, and 6 (Regulation and 

Operating Reserves) share operational characteristics of Schedules 4 and 9 (Imbalance 

services).65 

48. While Powerex agrees that resources capable of providing spinning and nonspinning reserves may be limited by response time requirements, Powerex argues that the 

existing market power screens nonetheless can be applied to operating reserve services.

66

 

49. With respect to Regulation and Frequency Response, some commenters argue that 

passage of the existing market power screens indicates lack of market power for that

service. For example, while EPSA agrees that the market power of sellers of Reactive 

Supply and Voltage Control service cannot be gauged by the existing market power 

screens due to significant technical and geographic impediments, it argues that 

Regulation and Frequency Response service is merely a derivative of a resource’s ability 

 

64 EEI Comments at 10.

65 Western Group Comments at 3.

66 Powerex Comments at 7 and 13.
Docket Nos. RM11-24-000 and AD10-13-000 - 36 -

to generate energy. Accordingly, EPSA argues that application of the existing market 

power screens to this ancillary service would be appropriate.

67

50. Powerex agrees that the existing market power screens could be applied to 

Regulation and Frequency Response service. Powerex believes that technical 

improvements such as the dynamic scheduling system adopted by some users of the 

Western Interconnection facilitate widespread delivery of regulating reserves, thus 

overcoming any locational requirements for that service, while any technical 

impediments could be overcome because AGC or equivalent power electronic controls 

could be added by most market participants if the markets provide correct price signals.

68

 

WSPP similarly argues that, while not all generators have the AGC equipment needed to 

provide Regulation and Frequency Response service, installation of this capability is an 

economic decision and is not such an impediment that it should be treated as a market 

defining barrier to entry.69

51. FTC Staff urges the Commission to recognize that even though a particular 

resource may not currently have the ability to provide a given ancillary service due to 

lack of relevant equipment, if such equipment could be installed in a timely fashion in 

response to high prices, then such resource should be considered a potential competitor 

 

67 EPSA Comments at 6.

68 Powerex Comments at 12.

69 WSPP Comments at 8. Iberdrola supports these WSPP comments by reference.
Docket Nos. RM11-24-000 and AD10-13-000 - 37 -

for purposes of market power analysis. Accordingly, FTC Staff suggests that the 

Commission revise its market power analysis to incorporate as existing market 

participants those potential entrants that are likely to enter a given ancillary service 

market (i.e., install needed equipment such as AGC) rapidly and profitably should market 

prices justify such entry.70

52. EEI argues that, before extending application of the existing market power screens 

to Regulation and Frequency Response, the Commission should separate this service into 

two separate ancillary services: primary frequency control and secondary frequency 

control. EEI argues that secondary frequency control, which it labels as Regulation, is a 

prime candidate to be extended the rebuttable presumption (i.e., to be subject to the 

existing market power screens).

71

53. Two parties filed comments opposing the application of existing market power 

screens to non-imbalance ancillary services. Southern California Edison and TAPS state 

that they agree with the NOPR’s reasoning as to why the existing market power screens 

cannot be applied to non-imbalance ancillary services.72 Remaining commenters did not 

address the question of applying the existing market power screens to non-imbalance 

ancillary services.

 

70 FTC Staff Comments at 6-8.

71 EEI Comments at 10-11.

72 Southern California Edison Comments at 1-2; and TAPS Comments at 9-10.
Docket Nos. RM11-24-000 and AD10-13-000 - 38 -

Commission Determination

54. Upon consideration of the comments to the NOPR, and as discussed more fully 

below, the Commission will allow third-party sellers passing existing market power 

screens to sell Operating Reserve-Spinning and Operating Reserve-Supplemental services 

at market-based rates to a public utility transmission provider within the same balancing 

authority area, or to a public utility transmission provider in a different balancing 

authority area, if those areas have implemented intra-hour scheduling for transmission 

service that supports the delivery of operating reserve resources from one balancing 

authority area to another. Commenters have persuaded us that to the extent there are 

technical requirements and limitations associated with operating reserves, they do not

materially distinguish resources capable of providing energy and capacity from those 

capable of providing operating reserves. As with the imbalance services, however, the 

Commission finds that the delivery of operating reserves from one balancing authority 

area to another may be limited by hourly scheduling practices in place within certain 

regions, which could impact the assumption in the existing market power screens that 

first-tier resources are able to compete with home balancing authority area resources. 

Therefore, the Commission will allow third-party sellers passing existing market power 

screens to sell these services to public utility transmission providers to the extent withinhour transmission service scheduling practices, including intra-hour transmission 

scheduling mandated by Order No. 764, support the delivery of operating reserves from 

one balancing authority area to another. 
Docket Nos. RM11-24-000 and AD10-13-000 - 39 -

55. In contrast, the Commission affirms the preliminary finding in the NOPR that the 

set of resources capable of providing Regulation and Frequency Response service and 

Reactive Supply and Voltage Control service would differ significantly from the broader 

set of resources capable of supplying energy and capacity. Accordingly, the Avista 

restrictions will remain in place for sales of those services to public utility transmission 

providers at market-based rates. As noted below, the Commission will establish a new 

proceeding to further explore the technical, economic and market issues concerning the 

provision of Reactive Supply and Voltage Control service and Regulation and Frequency 

Response service.

Operating Reserve Services

56. Operating Reserve-Spinning and Operating Reserve-Supplemental are products 

designed to serve load temporarily in the event of contingencies. As such, sellers must 

ensure the availability of capacity sufficient to address a contingency event and, if the 

contingency occurs, energy must be supplied from that capacity. While the NOPR 

preliminarily found that the operating reserve products appeared to require the 

availability of resources with relatively fast ramping capabilities, and in the case of offline resources used for operating reserve-supplemental, relatively fast start-up capabilities 

as well,

73 comments to the NOPR argue otherwise. 

 

73 See NOPR, FERC Stats. & Regs. ¶ 32,690 at P 22.
Docket Nos. RM11-24-000 and AD10-13-000 - 40 -

57. Many comments to the NOPR make the case that the flexibility and response time 

requirements associated with operating reserve services are not so significant that the 

universe of resources that can provide these services is meaningfully different than the 

universe of resources used to assess energy and capacity market power. While traditional 

generation scheduling practices only require the resources that provide energy and 

capacity to be able to change output levels once an hour, the record in this proceeding 

indicates that most resources can change output levels on shorter time scales. In other 

words, most conventional resources can change output in response to contingency events 

on a time scale shorter than the typical hourly scheduling window, even if in the past they 

have only been selling hourly block energy and capacity. Therefore, the Commission 

will allow third-party sellers passing existing market power screens for energy and 

capacity for a given market to also sell Operating Reserves-Spinning and Operating 

Reserves-Supplemental services at market-based rates to a public utility transmission 

provider within the same balancing authority area, or to a public utility transmission 

provider in a different balancing authority area, if within-hour transmission scheduling 

practices in those areas support the delivery of operating reserves from one balancing 

authority area to another.

74

 

74 As with Energy Imbalance and Generator Imbalance services, we clarify that the 

authorization to undertake sales at market-based rates may include both the capacity and 

the energy associated with providing Operating Reserve-Spinning and Operating 

Reserve-Supplemental services.
Docket Nos. RM11-24-000 and AD10-13-000 - 41 -

58. We note that our approach for market-based sales of operating reserves differs 

slightly from the reforms adopted above for sales of imbalance services. We have found 

above that the existence of 15-minute scheduling in a region renders the set of resources 

capable of supplying imbalance services substantially similar to the set of resources 

capable of providing energy and capacity so that the same market power screens can be 

applied to both sets of services. This may not be the case in all circumstances for 

potential sellers of operating reserves and, therefore, we require such entities to explain in 

their market-based rate applications for such authority how the scheduling practices in 

their regions support the use of operating reserves. For example, while 15-minute 

scheduling might be sufficient for Operating Reserve-Supplemental because this service 

only requires designated resources to be available within a short period of time,75 

15-minute scheduling by itself may not be sufficient for Operating Reserve-Spinning, 

which requires designated resources to be available immediately.76 The Commission 

recognizes that unlike the imbalance services, operating reserve services are targeted only 

at addressing contingency events, and some regions such as WECC may have already 

developed within-hour capacity tagging and scheduling practices intended to support the 

 

75 See pro forma OATT, Schedule 6 “Supplemental Reserve Service is needed to 

serve load in the event of a system contingency; however, it is not available immediately 

to serve load but rather within a short period of time.”

76 Id. Schedule 5 “Spinning Reserve Service is needed to serve load immediately 

in the event of a system contingency.”
Docket Nos. RM11-24-000 and AD10-13-000 - 42 -

use of operating reserves across multiple balancing authority areas.

77

 These are the types 

of region-specific practices that sellers seeking authority to sell operating reserves to 

public utility transmission providers should describe in their market-based rate 

applications. Thus, as of the effective date of this Final Rule, both sellers that have a 

market-based rate tariff on file as of that date and applicants seeking new market-based 

rate authority must satisfactorily make the above showing and receive Commission 

authorization before making sales of Operating Reserve-Spinning and Operating 

Reserve-Supplemental to a public utility that is purchasing Operating Reserve-Spinning 

and Operating Reserve-Supplemental to satisfy its own open access transmission tariff 

requirements to offer ancillary services to its own customers.

Regulation and Reactive Power Services

59. The Commission affirms the preliminary finding in the NOPR that the more 

stringent technical and geographic considerations associated with the regulation and 

reactive power ancillary services suggest that they are not simple combinations of basic 

energy and capacity products. Most commenters addressing this issue agree that the set 

of resources considered by the existing market power screens would differ too 

 

77 See, e.g., WECC Regional Business Practice INT-018-WECC-RBP-0, Tagging 

Protocols, at WR5.1 and WR5.2, defining capacity e-tags for, respectively, spinning 

reserves and non-spinning reserves as “product(s) that can be activated through the 

adjustment of a capacity e-tag.” Available at 

http://www.wecc.biz/library/Documentation%20Categorization%20Files/Forms/AllItems

.aspx?RootFolder=%2flibrary%2fDocumentation%20Categorization%20Files%2fRegion

al%20Business%20Practices&FolderCTID=0x01200015E7900DB2E794468FDE06D52

0B95C07 .
Docket Nos. RM11-24-000 and AD10-13-000 - 43 -

significantly from the set of resources that would be considered by market power 

analyses designed specifically for Reactive Supply and Voltage Control service. 

60. While some commenters do argue that the existing market power screens are 

adequate for Regulation and Frequency Response service, we are not persuaded by their 

arguments on the record here. We continue to believe that significant technical 

requirements, such as the need for AGC equipment, limit the set of resources capable of 

supplying this ancillary service. While we agree in principle with FTC Staff’s comments 

that potential competitors could be viewed as existing competitors for purposes of market 

power analysis if it is known that they can install needed equipment rapidly and 

profitably in response to appropriate price signals, the record does not conclusively 

support the notion that such equipment upgrades (e.g., to install AGC equipment in an 

existing generator) can be accomplished in such a manner. Although Powerex asserts 

that AGC or equivalent power electronic controls could be added by most market 

participants if the markets provide correct price signals, and WSPP asserts that the 

addition of AGC is an economic decision, we are not persuaded based on the limited 

information in the record before us.. Also, the record indicates that third-party sellers of 

Regulation and Frequency Response service might need to enter into or facilitate special 

arrangements between neighboring balancing authorities, such as dynamic scheduling or 

pseudo-tie arrangements, in order to make sales outside of their home balancing authority 

area. 

61. Accordingly, because the record before us does not support a modification at this 

time, the Avista restrictions will remain in place for sales of Regulation and Frequency 
Docket Nos. RM11-24-000 and AD10-13-000 - 44 -

Response and Reactive Supply and Voltage Control services to a public utility 

transmission provider that is purchasing these ancillary services to satisfy its own OATT 

requirements to offer ancillary services to its own customers. However, the Commission 

intends to gather more information regarding this issue in a separate, new proceeding that 

will further explore the technical, economic and market issues concerning the provision 

of Reactive Supply and Voltage Control service and Regulation and Frequency Response 

service. Such proceeding will consider, among other things, the ease and costeffectiveness of relevant equipment upgrades, the need for and availability of appropriate 

special arrangements such as dynamic scheduling or pseudo-tie arrangements, and other 

technical requirements for provision of Regulation and Frequency Response and Reactive 

Supply and Voltage Control services. 

b. Optional Market Power Screen

Commission Proposal

62. In the NOPR, the Commission proposed a new optional market power screen

solely applicable to ancillary services, together with a limited new reporting requirement 

that would provide potential sellers of ancillary services with the information needed to 

develop market power analyses using that optional market power screen.78 Specifically, 

the optional market power screen for an ancillary service would compare the amount of 

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

 

78 NOPR, FERC Stats. & Regs. ¶ 32,690 at PP 25-30.
Docket Nos. RM11-24-000 and AD10-13-000 - 45 -

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

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

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

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

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

percent of the relevant aggregate requirement for an ancillary service would receive a 

rebuttable presumption that they lack horizontal market power for the ancillary service in 

question. 

63. In order to provide sellers with information as to the buyer’s aggregate 

requirement for an ancillary service, the Commission proposed to require each public 

utility transmission provider to publicly post on its OASIS the aggregate amount (MW or 

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

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

For example, a transmission provider may report that it has historically maintained 100 

MW of Regulation and Frequency Response reserves for its balancing authority area and 

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

balancing authority area. 

Comments

64. Some commenters support the optional market power screen on the basis that it 

provides a practical alternative to performing a traditional market power analysis, given 

the data constraints associated with the latter. WSPP, for example, states that the 

optional market power screen is a constructive response to the disconnection between 
Docket Nos. RM11-24-000 and AD10-13-000 - 46 -

regulatory market power study requirements and the incapability of market participants to 

perform those studies due to lack of data.

79

 WSPP states that it strongly supports the 

Commission’s proposal that public utility transmission providers be required to post the 

information needed for sellers to prepare the optional market power screen if the 

rebuttable presumption applicable to the imbalance ancillary service is not extended to all 

ancillary services.80

65. Public Interest Organizations argue that the optional screen is similar in intent to a 

de minimis capacity threshold and, as such, can remove the barrier of a burdensome 

market power analysis for smaller entities.81 The Solar Energy Association asserts that 

the optional market power screen likely will broaden the number of participants in the 

markets for certain ancillary services.82 Electricity Consumers similarly argues that the 

optional market power screen should reduce barriers to ancillary service providers and 

increase the supply of ancillary services in a timely and cost-effective manner.83

66. However, there was no consensus among the commenters supporting the proposed 

optional market power screen regarding the necessary granularity of the associated 

reporting requirement. Some commenters, such as WSPP and Shell Energy, argue that 

 

79 WSPP Comments at 12. 

80 Id. at 10. 

81 Public Interest Organizations Comments at 6. 

82 Solar Energy Association Comments at 5. 

83 Electricity Consumers Comments at 3.
Docket Nos. RM11-24-000 and AD10-13-000 - 47 -

postings should reflect a transmission provider’s annual peak requirements for ancillary 

services, rather than annual averages. WSPP argues that posting an annual average 

would tend to understate requirements for higher periods, thereby skewing screen results 

in the direction of violations.84 Similarly, Shell Energy states that relying on annual 

peaks is preferable to annual averages because it better reflects the amounts that 

transmission providers need to procure. Shell Energy further argues that postings of 

annual peak values are preferable to postings of seasonal or quarterly values, which Shell 

Energy claims would be burdensome for transmission providers and suppliers.85

67. Conversely, the ESA, Beacon, and California Storage Alliance recommend that 

public utilities provide seasonal and time-of-day requirements (if any) for each ancillary 

service versus a single average annual amount and note that this is consistent with the 

type of data provided by RTOs/ISOs in the open wholesale markets.

86

 

68. Some commenters oppose the optional market power screen, arguing that it would 

yield too many false positives because it does not measure a seller’s ability to supply 

relative to the total potential supply of the overall market. EPSA, for example, argues 

that the optional screen would routinely result in false-positive indications of market 

 

84 WSPP Comments at 11. 

85 Shell Energy Comments at 8. 

86 ESA Comments at 7; Beacon Comments at 6; and California Storage Alliance 

Comments at 4. 
Docket Nos. RM11-24-000 and AD10-13-000 - 48 -

power.

87

 EPSA states that if the Commission decides to use a threshold test, it should 

compare the subject generator to total product capability, not merely the quantity 

demanded.88 EEI similarly argues that the optional screen likely will result in many 

suppliers failing the 20 percent threshold.89 EEI contends that there are alternatives that 

would refine the test to be more applicable and useful in promoting robust participation in 

competitive ancillary services markets in bilateral regions. EEI offers as an example 

requiring transmission providers to report on its OASIS in the aggregate its historical 

demand and its historical ability to supply the relevant ancillary services. EEI offers that 

if the Commission decides to pursue optional screen it should have a technical 

conference.

90

69. Powerex claims that the optional market power screen does not appear workable in 

certain respects and is likely to result in too many false positives.91 Powerex argues that 

establishing a test that is overly restrictive, and that a majority of sellers will not be able 

to satisfy, will create a significant administrative burden that will continue to pose an 

obstacle to the development of competitive markets for ancillary services.92 Powerex 

 

87 EPSA Comments at 6.

88 Id. at 7. 

89 EEI Comments at 16. 

90 EEI Comments at 15. 

91 Powerex Comments at 16.

92 Id. at 17. 
Docket Nos. RM11-24-000 and AD10-13-000 - 49 -

asserts that when using market shares as a metric of market power, the proper 

measurement is a seller’s ability to supply relative to the total potential supply of the 

overall market.93

70. Morgan Stanley argues that the optional market power screen does not provide a 

complete picture of an entity’s market power and that it is more relevant to compare the 

amount of supply a seller controls to the total supply available and the total market 

demand, than it is to compare it to a single buyer’s requirements.94 Morgan Stanley 

claims that a seller actually could have greater market power even if it only can serve a 

small portion of the buyer’s aggregate requirements if the buyer has no other viable 

options for procuring the remaining portion of its ancillary service needs.95

71. Other commenters oppose the optional market power screen on the basis that its 

need and usefulness is unclear. For example, TAPS argues that the usefulness of the 

optional screen is uncertain, particularly given the acknowledged data limitations. TAPS 

further argues that one cannot be confident that the proxy would provide a meaningful 

screen for market power.96

 

93 Id. at 19. 

94 Morgan Stanley Comments at 6.

95 Id. at 7. 

96 TAPS Comments at 14. 
Docket Nos. RM11-24-000 and AD10-13-000 - 50 -

72. The California PUC states that is sees no need for alternative methodologies and 

further argues that a 20 percent threshold is too high for ancillary services.

97

 The Hydro 

Association also states that it does not see a need at this time for the Commission to 

develop alternative market screens.98

Commission Determination

73. The Commission will not adopt the optional market power screen for ancillary 

services as proposed in the NOPR. As suggested by EEI, ESPA and others, the fact that 

the proposed optional screen would not consider the full amount of competing supply 

available to a buyer likely means that the screen may result in so many false positive

indications of potential market power that it would provide little benefit to the effort to 

foster competition in ancillary service markets.

74. The comments also indicate that establishing the reporting requirements associated 

with the optional market power screen would not be a trivial task, particularly given the 

lack of consensus regarding the granularity of information needed. The Commission 

believes that the costs of developing and imposing this new reporting requirement on 

transmission providers might not be justified, particularly in light of the other actions 

taken in this Final Rule. The need for the proposed optional screen, and its associated 

reporting requirement, is significantly reduced because this Final Rule, as explained 

 

97 California PUC Comments at 5-6. 

98 Hydro Association Comments at 8. 
Docket Nos. RM11-24-000 and AD10-13-000 - 51 -

above, will permit sellers to apply the existing market power screens to imbalance and 

operating reserve ancillary services. As such, the Commission has determined not to 

adopt the optional market power screen and its associated reporting requirement.

2. Alternative Mitigation 

75. In the NOPR, the Commission proposed to permit sellers unable or unwilling to 

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

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

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

be allowed where the purchasing entity is a public utility transmission provider 

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

to its own customers.99 Such a price cap would have been based on one of the two 

possible OATT ancillary service rate caps discussed below and, as in Avista, the 

Commission proposed that sales under these price caps would only be permitted in 

geographic markets where the seller has been granted market-based rate authority for 

sales of energy and capacity. In addition, a seller unable to perform a market power 

study for ancillary services could rely on competitive solicitations meeting certain 

minimum requirements in order to make sales in geographic markets where the seller has 

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

 

99 NOPR, FERC Stats. & Regs. ¶ 32,690 at PP 33-40.
Docket Nos. RM11-24-000 and AD10-13-000 - 52 -

a. Use of Price Caps

Commission Proposal

76. In the NOPR, the Commission proposed two cost-based mitigation measures as 

alternatives to the prohibition adopted in Avista with regard to sales to a public utility 

transmission provider that is purchasing ancillary services to meet its OATT 

requirements to offer ancillary services to its own customers. Sales of ancillary services 

at or below either alternative would be permitted. Under the first, third parties would be 

permitted to sell to a public utility transmission provider at rates not to exceed the buying 

public utility transmission provider’s existing OATT rate for the same ancillary service. 

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

public utility transmission provider at rates not to exceed the highest public utility 

transmission provider OATT rate within the relevant geographic market for physical 

trading of the ancillary service in question. The Commission proposed that the seller (or 

group of sellers) would file with the Commission a proposal that defines the scope of a 

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

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

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

physically possible. 

i. Single OATT Rate Cap Option

Comments

77. There was a range of support for the establishment of a rate cap at the buyer’s 

OATT rate for the same ancillary service. TAPS and Southern California Edison support 
Docket Nos. RM11-24-000 and AD10-13-000 - 53 -

this proposal outright as an option to enable ancillary service sales.100 EEI states that 

while the Commission should primarily rely on existing market power analyses and 

screens to allow third-parties to sell certain ancillary services at market-based rates, costbased mitigation measures are also appropriate in certain seller-specific circumstances. 

EEI states that these two alternative options should be included in any Final Rule. EEI 

contends that this flexibility should encourage an increased number of participating 

sellers in bilateral markets, provide options for transmission providers to meet 

obligations, create market efficiencies, and potentially lower prices.

101

78. WSPP states that it supports inclusion of this option to enhance flexibility in the 

sale of ancillary services, but with reservations. WSPP’s reservations essentially concern 

whether existing OATT ancillary services rates provide appropriate price signals. WSPP 

contends that because reserve sales are from the same units as energy sales, mitigation 

price caps that fail to take opportunity costs into account during peak periods are unduly 

low.102 Separately, WSPP asks the Commission to clarify that for the single OATT rate 

cap there is no filing with the Commission as a prerequisite to the sale.

103 AWEA and 

Solar Energy Association either support the proposal or do not state opposition to it.104

 

100 TAPS Comments at 15-18 and Southern California Edison Comments at 6.

101 EEI Comments at 18-19.

102 WSPP Comments at 15.

103 Id. at 14.

104 AWEA Comments at 3 and Solar Energy Association Comments at 6.
Docket Nos. RM11-24-000 and AD10-13-000 - 54 -

Iberdrola supports WSPP’s and AWEA’s comments by reference.105 Electricity 

Consumers state that they do not object to the proposed alternatives provided that they 

are in fact promulgated as alternatives to the proposed revisions to the market power 

analysis.106 

79. Although ESA, Beacon, and California Storage Alliance all support this proposal, 

they each argue that for this mitigation measure to be successful in fostering robust 

competitive markets, the Commission must ensure that cost-based schedules for ancillary 

services, in particular Regulation and Frequency Response, are compared on an “applesto-apples” basis taking into account resource performance.

107

80. Some commenters oppose this price cap proposal unless the cap can be raised in 

some way. For example, Shell Energy argues that a cap based on the buyer’s OATT rate 

would not produce prices high enough to entice competitive supply. Instead, Shell 

Energy suggests establishment of a price cap set at 200 percent of the buyer’s OATT rate 

for the ancillary service in question.108 Similarly, EPSA asserts that cost-based price caps 

systematically fail to represent the true value of capacity products and will fail to allow a 

full range of economic tradeoffs in the bilateral markets. EPSA states support for the use 

 

105 Iberdrola Comments at 3.

106 Electricity Consumers Comments at 4.

107 ESA Comments at 8-10; Beacon Comments at 7-9; and California Storage 

Alliance Comments at 5-6.

108 Shell Energy Comments at 8-9.
Docket Nos. RM11-24-000 and AD10-13-000 - 55 -

of price caps as a last resort, and only if they reflect the seller’s lost opportunity costs as 

represented by energy transactions during a recent historical period.109 Powerex makes 

similar arguments, favoring the use of energy price indices to represent lost opportunity 

costs. Failing that, Powerex argues that a component for transmission costs for remote 

suppliers should be added to any OATT-based price cap.110

81. ENBALA argues that a cost-based cap limited to the buying utility’s OATT rate 

might be too restrictive and lead the Commission to scrutinize more agreements than 

necessary, but ENBALA states that “Reactive Supply and Voltage Control service should 

be excluded from the regional price cap, being priced by the buying utility’s OATT rate 

to reflect the geographic limitations of the ancillary service.”

111

 

Commission Determination

82. As one option available to sellers, the Commission will permit market-based sales 

of Regulation and Frequency Response service and Reactive Supply and Voltage Control 

service to public utility transmission providers at rates not to exceed the buying public 

utility transmission provider’s OATT rate for the same service.112 We find that a price 

cap based on the buying public utility transmission provider’s OATT rate for the same 

 

109 EPSA Comments at 9-10.

110 Powerex Comments at 25-29. 

111 ENBALA Comments at 2-4.

112 We do not apply this mitigation option to the other OATT ancillary services 

because this Final Rule allows sales of those services at market-based rates for any seller 

that has market-based rate authority for energy and capacity.
Docket Nos. RM11-24-000 and AD10-13-000 - 56 -

ancillary service would produce a just and reasonable rate, and do so in a manner that is 

administratively simple. As discussed in the NOPR,113 because the buying public utility 

transmission provider’s OATT ancillary service rates have already been found to be just 

and reasonable, it is reasonable to find that any third-party sales of the same ancillary 

service to that buyer at or below that buyer’s own approved rates for that service would 

also be just and reasonable. Accordingly, we will not require sellers to make a separate 

showing as to the justness and reasonableness of such rates and will allow sellers to make 

third-party sales of such services at rates as discussed here as of the effective date of this 

Final Rule.

83. Allowing the sale of ancillary services below the purchasing public utility 

transmission provider’s OATT rate is a reasonable extension of the mitigation measure 

relied upon by the Avista policy itself. As discussed earlier,114 the Avista policy sought to 

protect buyers of third-party ancillary services from potential exercise of market power 

by ensuring that they would continue to have access to cost-based ancillary services from 

transmission providers, in effect limiting the price at which customers are willing to buy 

ancillary services from third-parties. The result of the Avista mitigation measure is an 

implicit soft cap on the price at which third-party ancillary services could be offered to 

 

113 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 34.

114 See supra P 7.
Docket Nos. RM11-24-000 and AD10-13-000 - 57 -

non-transmission provider customers. The price cap proposal adopted here extends this 

concept to transmission providers by creating an explicit price cap at the same level.

84. While a few commenters opine that a cap based on the buyer’s OATT rate would 

not produce prices high enough to entice competitive supply, the Commission finds that, 

given the reforms adopted elsewhere in this Final Rule, it is appropriate to take the more 

conservative step of adopting a price cap based on the buyer’s OATT rate for sales of 

Regulation and Frequency Response service and Reactive Supply and Voltage Control 

service to public utility transmission providers. This measure can be implemented 

quickly and easily with few administrative burdens on either the Commission or the 

industry. Alternative proposals by commenters would require more complicated design, 

analysis, and oversight to ensure that they achieve just and reasonable rates.

85. With respect to the arguments of ESA, Beacon, and California Storage Alliance

that for this mitigation measure to be successful, the Commission must ensure that costbased schedules for ancillary services are compared on an “apples-to-apples” basis taking 

into account resource performance, the Commission addresses this issue below in subsection B of this Final Rule. 

ii. Regional OATT Rate Cap Option

Comments

86. Some commenters, such as ESA, Beacon, and the California Storage Alliance, 

support the regional OATT rate cap option on the basis that it is a reasonable 
Docket Nos. RM11-24-000 and AD10-13-000 - 58 -

approximation of the cost of entry.115 ENBALA also expresses support for a regional 

cost-based rate cap, arguing that it provides an adequate alternative to the current formal 

market power requirement.116 EEI and Electricity Consumers also express support for a 

regional OATT rate cap but offer no specific recommendations.117

87. Southern California Edison states that it supports a cap based on the highest 

OATT rate within the geographic market as long as it is capped at the lesser of (a) the 

highest OATT rate in the market or (b) three times the median OATT rate in the relevant 

geographic market. Southern California Edison explains that it proposes this 

modification to protect against having a small balancing authority area with an extremely 

high outlier rate setting the cap.118

88. Other commenters criticize the highest OATT rate cap proposal. Some parties, 

such as WSPP, EPSA, and Powerex, argue that setting caps based on cost-based rates 

would not allow sellers to recover foregone opportunity costs associated with energy 

sales and thus would fail to create any incentives for sellers to enter ancillary service 

markets. They argue that this is particularly true for short-term ancillary service sales, 

given that opportunity costs vary materially for hourly, daily, monthly, and seasonal 

 

115 ESA Comments at 10; California Storage Alliance Comments at 7; and Beacon 

Comments at 9.

116 ENBALA Comments at 2.

117 EEI Comments at 18-19; and Electricity Consumers Comments at 4. 

118 Southern California Edison Comments at 6-7. 
Docket Nos. RM11-24-000 and AD10-13-000 - 59 -

periods, but these variations are not reflected in OATT rates and therefore would not be 

reflected in the cap. 

89. For example, Powerex contends that any alternative price cap must be high 

enough to create economic incentives for potential sellers to forego other opportunities, 

namely, energy sales.119 Powerex argues that setting price caps based on transmission 

providers’ cost-based rates in many instances will not allow sellers to recover the 

foregone opportunity costs associated with energy sales and that this is particularly true 

for short-term ancillary service sales.120 Powerex states that short-term energy prices in 

the CAISO and other Western markets are frequently several-fold higher than Northwest 

transmission providers’ OATT rates for ancillary services.121

90. Similarly, EPSA argues that a price cap should include a seller’s lost opportunity 

costs, represented by energy transactions during a recent historical period. EPSA states 

that it is critically important to include lost opportunity costs, in order to allow a 

generator to rationally choose between producing energy and not producing energy.122

91. WSPP asserts that the Commission’s observation that the OATT rate could be 

indicative of the cost of new entry appears speculative. WSPP contends that a cost-based 

rate may reflect a fully or substantially depreciated unit, rather than the cost of new 

 

119 Powerex Comments at 26. 

120 Id. 

121 Id. at 27. 

122 EPSA Comments at 9-10. 
Docket Nos. RM11-24-000 and AD10-13-000 - 60 -

construction.123 WSPP also argues that because reserve sales are made from the same 

resources as energy sales, mitigation price caps that fail to take opportunity costs into 

account during peak periods are unduly low.124

92. Other commenters raise concerns about setting the geographic boundaries for a 

regional OATT rate cap. Shell Energy asserts that identifying the region in which an 

ancillary service can be physically traded can be difficult and recommends that the 

Commission, rather than sellers, identify the relevant trading regions and post that 

information on the Commission’s website.125 TAPS argues that a regional price cap 

would invite gerrymandering and provide no assurance that the resulting cap is a more 

reasonable approximation of the cost of new entry.126 TAPS argues that significant 

physical constraints limit the provision of ancillary services over a geographic area.127

TAPS contends that the regional OATT rate cap proposal is not defensible as either a 

cost-based or market-based rate and is at odds with the physical limitations on the 

provision of ancillary services in non-RTO regions.128 TAPS contends that another 

regional transmission provider’s higher rate (i.e., the highest regional rate) does not bear 

 

123 WSPP Comments at 15. 

124 Id. at 15. 

125 Shell Energy Comments at 9. 

126 TAPS Comments at 22. 

127 Id. at 20. 

128 Id. at 2. 
Docket Nos. RM11-24-000 and AD10-13-000 - 61 -

any relationship to either a third-party supplier’s or the purchasing transmission 

provider’s cost of supply.129

Commission Determination 

93. The Commission will not adopt the NOPR proposal that would allow sellers to 

propose a price cap equal to the highest OATT rate within a specified region. Based on 

the comments received, the Commission concludes that use of a regional OATT rate cap 

would be inadequate to ensure that third-party sellers’ rates remain just and reasonable. 

In the NOPR, the Commission suggested that this mitigation proposal might be justified 

on a cost basis in that the highest regional rate may be a reasonable approximation of the 

cost of new entry into the region in question.130 However, the record developed in this 

proceeding does not support such a conclusion at this time.

94. We also share commenters’ concerns associated with defining appropriate regions

for purposes of setting regional price caps. The Commission is concerned that sellers 

would have an incentive to “gerrymander” or “cherry-pick” regional definitions to ensure 

inclusion of a high-cost ancillary service provider. In light of the other actions taken in 

this Final Rule, the Commission believes it would not be productive to undertake the 

analyses necessary to establish seller-specific regions for various ancillary services.

 

129 Id. at 19. 

130 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 36.
Docket Nos. RM11-24-000 and AD10-13-000 - 62 -

b. Competitive Solicitations

Commission Proposal

95. The NOPR proposed to allow applicants to engage in sales to a public utility that 

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

services to its own customers where the sale is made pursuant to a competitive 

solicitation that meets the following guidelines: (1) transparency – the competitive 

solicitation process should be open and fair; (2) definition – the product or products 

sought through the competitive solicitation should be precisely defined; (3) evaluation –

evaluation criteria should be standardized and applied equally to all bids and bidders; 

(4) oversight – an independent third-party should design the solicitation, administer 

bidding, and evaluate bids prior to the company’s selection;131 and (5) competitiveness –

adequate seller interest to ensure competitiveness.

Comments

96. Commenters generally support the proposal to permit competitive solicitations as 

an alternative to performing a market power study.132 EEI, for example, expresses 

support for competitive procurement as an option for long-term resource planning.133 

 

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

132 EPSA Comments at 8-9; EEI Comments at 19-20; ESA Comments at 10-11; 

Beacon Comments at 9-11; California Storage Alliance Comments at 7; and ENBALA 

Comments at 4.

133 EEI Comments at 19-20. 
Docket Nos. RM11-24-000 and AD10-13-000 - 63 -

EPSA states that the Commission’s proposed guidelines for competitive solicitations 

conform to general principles that EPSA has advocated for such processes.134 

97. Some commenters object to certain aspects of the Commission’s proposal. Most 

criticism is directed at the proposed requirement for independent third-party oversight of 

competitive solicitations. WSPP, for example, expresses support for competitive 

solicitations as a means of mitigating potential market power concerns but opposes the 

proposed oversight by an independent third party. WSPP argues that such oversight is 

unnecessary, and that the required filing is ample to demonstrate whether or not the 

solicitation yielded sufficient competition.135 Shell Energy agrees that third-party 

oversight of competitive solicitations is unnecessary, arguing that this requirement would 

hinder short-term procurement of ancillary services and make the solicitation process 

unfeasible except for long-term transactions.136

98. However, Morgan Stanley contends that it is not clear that the Commission’s 

competitive solicitation proposal would protect against market power. Morgan Stanley 

contends that a competitive solicitation only demonstrates lack of market power if it is 

robust enough to attract offers that, in aggregate, are significantly in excess of the 

quantity sought. Morgan Stanley states that it is not clear how a competitive solicitation 

 

134 EPSA Comments at 8-9. 

135 WSPP Comments at 17-18. 

136 Shell Energy Comments at 10. 
Docket Nos. RM11-24-000 and AD10-13-000 - 64 -

could help buyers looking to purchase such services on a short-term basis, although it 

might for the long-term provision of ancillary services.

137

Commission Determination

99. The Commission adopts the NOPR proposal to allow applicants to engage in 

market-based sales of ancillary services to a public utility that is purchasing ancillary 

services to satisfy its OATT requirements where the sale is made pursuant to a 

competitive solicitation that meets the requirements specified in the NOPR as numerated 

above, except as modified below. The Commission has relied on the use of competitive 

solicitations to mitigate affiliate abuse concerns when affiliates seek to enter into 

transactions pursuant to market-based rate authority.138 In that context, the Commission 

has adopted guidelines for independent, third-party review of competitive solicitations. 

The requirements proposed for sales of ancillary services to public utility transmission 

providers are based on these guidelines, which the Commission concludes are reasonable 

to adopt here with one exception. Upon review of comments, we have decided to 

partially eliminate the requirement that an independent third-party design and administer 

the solicitation and evaluate bids prior to the company’s selection. 

100. As proposed, the independent third-party review requirement would apply to all 

competitive solicitations. However, the record does not support imposing a requirement 

 

137 Morgan Stanley Comments at 8-9. 

138 See Boston Edison Co. Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 

(1991); Allegheny, 108 FERC ¶ 61,082.
Docket Nos. RM11-24-000 and AD10-13-000 - 65 -

for independent third-party review when none of the parties participating in a competitive 

solicitation is affiliated with the buying public utility transmission provider. If no 

affiliate of the buyer participates in the solicitation, there is no concern regarding 

preferential treatment and, therefore, no need for review by an independent third party. 

As commenters suggest, requiring an independent third-party reviewer could discourage 

the use of competitive solicitations as it would add to the cost and time needed to procure 

ancillary services. Some public utility buyers may have a short-term, unexpected need 

for ancillary services and therefore need to act quickly to fill this need. In such cases, the 

buyer itself will have to conduct the solicitation, with very limited time for independent 

review. The Commission therefore revises the NOPR proposal to require independent 

third-party review of competitive solicitations only when the buyer solicits offers from 

one or more of its affiliates.

101. However, the Commission emphasizes that any buyer seeking to procure ancillary 

services from unaffiliated sellers through a competitive solicitation will need to 

demonstrate compliance with the four other requirements: transparency, definition, 

evaluation, and competitiveness. In this regard, we reject Morgan Stanley’s assertion that 

the competitiveness requirement can only be met where a solicitation attracts offers that, 

in aggregate, are significantly in excess of the quantity sought. We believe there may be 

multiple methods of demonstrating adequate competitiveness, and we will review such 

proposals on a case-by-case basis. This will help ensure that any ancillary services 

procured in this manner are purchased at a competitive market price. At the same time, 

these requirements will not hinder buyers’ flexibility to design solicitations to meet their 
Docket Nos. RM11-24-000 and AD10-13-000 - 66 -

specific needs. This demonstration must be made through a filing under section 205 of

the Federal Power Act, submitted by the seller to the Commission prior to 

commencement of service under the third-party ancillary service sales agreement that 

results from the competitive solicitation. To be specific, the third-party seller will need to 

submit both the actual sales agreement and a narrative description of how the buyer’s 

competitive solicitation meets the requirements of this Final Rule. This narrative 

description will help demonstrate that exercise of market power was not a factor in the 

negotiation of the sales agreement, and therefore that the resulting rate is just and 

reasonable. 

B. Resource Speed and Accuracy in Determination of Regulation and 

Frequency Response Reserve Requirements

Commission Proposal

102. The Commission proposed in the NOPR to require that each public utility 

transmission provider submit provisions for inclusion in its OATT that take into account 

the speed and accuracy of regulation resources in determining its Regulation and 

Frequency Response reserve requirements. Among other things, this would allow

customers choosing to self-supply this service with faster responding or more accurate 

resources to self-supply with a lower volume of regulation capacity, or vice versa. The 

Commission stated that it expects to evaluate each proposed determination of regulation 

reserve requirements on a case-by-case basis. It also stated that each description of how 

the public utility will adjust its regulation capacity requirement must provide enough 

detail that an entity wishing to self-supply may compare the resources it is considering 
Docket Nos. RM11-24-000 and AD10-13-000 - 67 -

using with the resources that the public utility is using. The Commission sought 

comment on how speed and accuracy should be taken into account.139

Comments

103. A majority of commenters140 generally support the NOPR proposal to require each 

public utility transmission provider to submit provisions for inclusion in its OATT that 

take into account the speed and accuracy of regulation resources in determining its 

Regulation and Frequency Response reserve requirements. Electricity Consumers, Hydro 

Association, Morgan Stanley, California PUC, and EPSA highlight the benefits of 

increased transparency, to which EPSA adds that lack of transparency is an impediment 

to competitive compensation outside of ISOs/RTOs and contributes to a lack of a 

discernible market value for speed and accuracy. Other commenters, including Public 

Interest Organizations, Iberdrola, Morgan Stanley, and FTC Staff cite avoidance of undue 

discrimination, comparable treatment, and the potential that the NOPR proposal will 

encourage innovation and new entry, as reasons for supporting the proposal. Solar 

Energy Association supports taking into account the speed and accuracy of regulation 

 

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

140 These commenters include Beacon, California Storage Alliance, ESA, Hydro 

Association, Solar Energy Association, Public Interest Organizations, California PUC, 

AWEA, Morgan Stanley, EPSA, TAPS, FTC Staff, Electricity Consumers, and Iberdrola.
Docket Nos. RM11-24-000 and AD10-13-000 - 68 -

resources when establishing the rates that may be charged for those services, with faster 

and more accurate resources priced accordingly.141 

104. Hydro Association supports the idea of “pay for performance” standards that 

recognize the difference between accurate fast-responding resources versus resources that 

ramp more slowly and respond less nimbly, and agrees with the Commission that a caseby-case evaluation of each proposed determination is more appropriate than imposing a 

mandatory methodology. Similarly, California PUC states that transparency should act 

as a deterrent against discrimination, but cautions that the Commission should avoid an 

overly prescriptive methodology that may dictate the amount of regulation resources that 

are needed.

105. Several other commenters, including Beacon, ESA, California Storage Alliance, 

and Morgan Stanley, encourage the Commission to require transmission providers to 

provide an explanation of how they set their regulation reserve requirements. ESA,

Beacon, and California Storage Alliance propose five elements of an explanation that 

each transmission provider should be required to provide about how it sets its regulation 

reserve requirement,142 as well as a list of specific information that each transmission 

 

141 Solar Industry Association Comments at 3. 

142 The five elements are: (1) a description of the calculation; (2) the metric which 

is used to set the requirement; (3) the average performance of the existing Regulation 

assets; (4) the speed and accuracy of the units currently in place (including ramp-rate and 

accuracy); and (5) sufficient data for a third party to reproduce the results, including 

posting ACE data on its OASIS reporting. ESA Comments at 12-13; Beacon Comments 

at 12; and California Storage Alliance Comments at 6.
Docket Nos. RM11-24-000 and AD10-13-000 - 69 -

provider should make available.143 Morgan Stanley also urges the Commission to require 

public utility transmission providers to provide demonstrations of equivalent treatment 

for their own or their affiliate’s requirements to ensure that there is no undue 

discrimination, and to establish a process for market participants to challenge and resolve 

the speed and accuracy assumptions and requirements that public utility transmission 

providers publish.144 Beacon and ESA also state that ideally the Commission would 

require each utility to develop a conversion formula or chart that specifies how much 

capacity a transmission customer must self-supply given a certain ramp-rate and 

accuracy.

106. ESA, Beacon, Public Interest Organizations, California Storage Alliance, and 

AWEA advocate extending the requirement of accounting for speed and accuracy in 

regulation service to public utilities meeting their own needs, including via third-party 

suppliers, not simply to transmission customers choosing to self-supply.145 AWEA 

argues that holding more reserves than needed may result in rates that are not just and 

reasonable.146 ESA, Beacon, Public Interest Organizations, and California Storage 

 

143 Each entity proposes a bulleted list of nine items including generation capacity 

available to provide regulation, rates, costs, accuracy and CPS scores, and representative 

ACE data. ESA Comments at 13; and Beacon Comments at 12-13.

144 Morgan Stanley Comments at 10.

145 Beacon and Public Interest Organizations support ESA’s comments regarding 

third party sales of regulation.

146 AWEA Comments at 4.
Docket Nos. RM11-24-000 and AD10-13-000 - 70 -

Alliance state that third party sales to a public utility that is purchasing ancillary services 

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

represents the most significant potential market for sales of ancillary services in nonRTO/ISO regions. Public Interest Organizations agree, arguing that neither the current 

rules nor the NOPR encourage transmission providers to improve the speed and accuracy 

of their owned or contracted frequency regulation resources, and that allowing generators 

to be displaced from providing frequency regulation will enable them to operate at a more 

stable output, which also can lower energy market prices. Public Interest Organizations 

contend that the existing OATT Schedule 3 rate treatment is no longer adequate to 

incorporate emerging technologies, and encourage the Commission to require that OATT 

Schedule 3 rates incorporate Order No. 755’s framework of an objective accuracy and 

performance determination, and that the amount of frequency regulation transmission 

customers are required to procure or self-supply takes into account the speed and 

accuracy capability of the ancillary service provider’s technology.

147

107. Parties that support extending the proposal to public utility transmission providers 

meeting their own needs also recommend that the Commission consider performancebased rate treatment for public utility investments and contracts with third-party ancillary 

service providers that allow the public utility to reduce the total capacity and cost of 

 

147 Public Interest Organizations Comments at 8.
Docket Nos. RM11-24-000 and AD10-13-000 - 71 -

providing regulation service while maintaining the same level of reliability.148 They 

argue that the potential benefits to ratepayers could justify allowing a performance-based 

incentive rate adder that public utility transmission providers could recover through rates, 

and that if the public utility can demonstrate that it will be able to reduce the total 

capacity and cost of providing regulation service and maintain the same degree of 

reliability, such treatment should result in public utilities improving the performance of 

their regulation fleet and in turn reducing expenses for frequency regulation, ultimately 

resulting in lower costs. 

108. TAPS asks the Commission to state explicitly that the NOPR’s proposal to 

account for the speed and accuracy of customer self-supplied regulating resources

includes demand resources and to state that such a finding would be consistent with 

OATT Schedule 3 and Order No. 755.149

109. EEI opposes the NOPR proposal. It contends that it is premature to require each 

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

Regulation and Frequency Response requirements, and requests that the Commission 

defer this proposal pending experience with secondary frequency control (i.e., regulation) 

in the ISOs and RTOs following the issuance of Order No. 755.150 EEI requests that the 

 

148 See comments of ESA, Beacon, Public Interest Organizations, and California 

Storage Alliance.

149 TAPS Comments at 27.

150 EEI Comments at 22-26.
Docket Nos. RM11-24-000 and AD10-13-000 - 72 -

Commission recognize the material differences between primary and secondary 

frequency control resources in the final rule. It argues that it is also premature to adopt 

requirements regarding primary frequency control, and recommends that the Commission 

encourage each balancing authority to continue investigating the role of various types of 

resources, and allow the industry to maintain its efforts to understand the relationship and 

interdependencies between primary and secondary frequency response. 

110. EEI contends that the assumption that faster responding technologies are 

necessarily more efficient than traditional methods of frequency regulation has not been 

substantiated. EEI explains that industry is still exploring frequency response, including 

current and historical primary and secondary control response performance, and that for 

system reliability it is important to maintain a balanced portfolio of resources including 

inertial response, governor response, and secondary frequency control (or regulation 

response). It further explains that, although OATT Schedule 3 groups primary and 

secondary frequency control into a single service, the nature of these services are distinct. 

With regard to secondary frequency control (regulation), EEI claims that the benefits 

from resources that ramp more quickly for purposes of secondary frequency control may 

be offset by a lack of capability to sustain that response, or to provide automatic primary 

frequency control. 

Commission Determination

111. The Commission will adopt the NOPR proposal with modification. Rather than 

requiring OATT Schedule 3 to include a description of how resource speed and accuracy 

will be taken into account in determining Regulation and Frequency Response reserve 
Docket Nos. RM11-24-000 and AD10-13-000 - 73 -

requirements, we will require each public utility transmission provider to add to its 

OATT Schedule 3 a statement that it will take into account the speed and accuracy of 

regulation resources in its determination of reserve requirements for Regulation and 

Frequency Response service, including as it reviews whether a self-supplying customer

has made “alternative comparable arrangements” as required by the Schedule. This 

statement will also acknowledge that, upon request by the self-supplying customer, the 

public utility transmission provider will share with the customer its reasoning and any 

related data used to make the determination of whether the customer has made 

“alternative comparable arrangements.”151 To aid the transmission customer’s ability to 

make an “apples-to-apples” comparison of regulation resources, the Commission will 

also amend Part 35 of its Regulations by adding a new section (k) to § 37.6,152 to require 

each public utility transmission provider to post certain Area Control Error (ACE) data 

described further below. We find that these reforms are necessary to address the 

potential for undue discrimination in the provision of Regulation and Frequency 

Response, including in instances when a customer self-supplies this service using its own 

resources or purchases from a third-party. Acknowledging the speed and accuracy of the 

resources used to provide this service will help to ensure that an appropriate quantity of 

 

151 See Appendix B for the revised Schedule 3 of the pro forma OATT provisions 

consistent with this Final Rule. 

152 This regulation will replace the like-numbered proposed regulation related to 

historical ancillary service requirements data posting from the NOPR that we decline to 

adopt in section II.A.1.b. of this Final Rule.
Docket Nos. RM11-24-000 and AD10-13-000 - 74 -

resources is utilized for self-supply, whether those resources are faster and more accurate 

or slower and less accurate than those used by the public utility transmission provider. 

The weight of comments support reform in this area, including arguments that such a 

reform will help foster innovation and the entry of newer resources into the market.

112. Under the current pro forma OATT, transmission customers considering using 

their own or third-party resources to self-supply regulation service are required to 

demonstrate to the public utility transmission provider that they have made “alternative 

comparable arrangements.” However, the pro forma OATT provides no further 

information as to how the determination of “alternative comparable arrangements” would 

be made. Moreover, the OATT contains no express obligation on the part of the 

transmission provider to consider the relative speed and accuracy of resources a customer 

might desire to use in self-supplying Regulation and Frequency Response service. A 

public utility transmission provider could require a customer seeking to self-supply 

regulation services to provide a volume of regulation reserves based on the characteristics 

of the resources used by the public utility transmission provider to provide regulation 

service, which may not be reflective of the characteristics of the customer’s resources. 

This could under- or overstate regulation reserve requirements depending on the relative 

characteristics of the resources at issue. It also could impair the customer’s ability to 

self-supply regulation requirements at the lowest possible cost.

153

 The Commission finds 

 

153 For example, a self-supplying customer could save money either by relying on 

a smaller amount of high quality regulation resources at a slightly higher per-unit price or 

(continued...)
Docket Nos. RM11-24-000 and AD10-13-000 - 75 -

that this lack of clarity as to the role of resource speed and accuracy in the determination 

of “alternative comparable arrangements” for regulation reserve requirements for selfsupplying transmission customers must be addressed in order to limit opportunities for 

potential discrimination in the provision of regulation service by public utility 

transmission providers. 

113. While the Commission initially proposed that each public utility transmission 

provider should amend its OATT to include a description of how regulation reserve 

requirement determinations would take into account speed and accuracy of resources, we 

believe the better course of action at this time is to place the obligation on the public 

utility transmission provider to take into account speed and accuracy without requiring it 

to develop detailed tariff language describing the specific process to be used. This will 

provide the public utility transmission provider with flexibility while also providing the 

customer with information. While a number of commenters suggested elements for what 

the public utility transmission provider should be required to provide, the clearest 

proposal in the comments related to this issue request that public utility transmission 

providers be required to provide current monthly and 12-month rolling average Control 

Performance Standard 1 (CPS1), Control Performance Standard 2 (CPS2) and Balancing 

 

by relying on a larger amount of lower quality regulation resources at a much lower perunit price. Provided that reliability is maintained, the transmission customer should have 

the ability to self-supply consistent with its preferences.
Docket Nos. RM11-24-000 and AD10-13-000 - 76 -

Authority ACE Limit (BAAL) scores for Frequency Regulation.154 However, by itself 

availability of such information would do nothing to explain how the public utility 

transmission provider determines regulation reserve amounts. Furthermore, while ACE 

information might help to characterize the speed and accuracy of the public utility 

transmission provider’s own regulation resources, the Commission believes that using the 

relatively long duration of monthly and 12-month rolling ACE averages implicit in these 

scores may not provide information useful for measuring performance over a fraction of 

an hour, which is the relevant time frame for Regulation and Frequency Response 

service. 

114. Accordingly, the Commission declines to impose a “one size fits all” approach to 

calculating regulation reserve requirements, consistent with the comments of Hydro 

Association and California PUC, and declines to require the inclusion of this process in 

Schedule 3. Rather, we require that Schedule 3 be amended to include a statement that 

the public utility transmission provider will take into account the speed and accuracy of 

regulation resources in determining reserve requirements for Regulation and Frequency 

Response service, including when reviewing whether a self-supplying customer has made 

“alternative comparable arrangements.” Self-supplying customers and their public utility 

transmission providers will then have a basis to study and negotiate appropriate 

 

154 CPS1 and CPS2 are described in NERC Reliability Standard BAL-001-0.1a —

Real Power Balancing Control Performance. The BAAL criterion is expected to replace 

CPS2 in that Reliability Standard when it becomes effective, pending final approval by 

NERC and the Commission.
Docket Nos. RM11-24-000 and AD10-13-000 - 77 -

arrangements case-by-case, very similar to how such interactions take place under other 

processes such as the interconnection process. 

115. That said, we agree with the comments of ESA, Beacon, and California Storage 

Alliance that transmission customers considering whether or not there would be any 

economic advantage to self-supply of Regulation and Frequency Response service 

requirements would need to be able to make an “apples-to-apples” comparison of their 

resources to those of their public utility transmission provider.155 Doing so would require 

the transmission customer to know both the potential avoided cost of purchasing from its 

public utility transmission provider, and some measure of the speed and accuracy of the 

public utility transmission provider’s Regulation resources. The first requirement is met 

through the rate filed in the public utility transmission provider’s OATT Schedule 3. We 

believe the second requirement can only be met through a new OASIS posting 

requirement.

116. As noted earlier, the public utility transmission provider’s CPS1, CPS2, and 

BAAL scores might address this need in concept, except that they currently reflect longterm averages that do not match the relevant time frame for Regulation and Frequency 

Response service. We believe the one-minute and ten-minute average ACE data 

collected by public utility transmission providers to produce the CPS1, CPS2, and BAAL 

scores would be more useful for this purpose because it does match the relevant time 

 

155 ESA Comments at 8-10; Beacon Comments at 7-9; and California Storage 

Alliance Comments at 5-6.
Docket Nos. RM11-24-000 and AD10-13-000 - 78 -

frame. Accordingly, in order to ensure a level of transparency adequate to support selfsupply decision-making by transmission customers, we will require public utility 

transmission providers to post historical one-minute and ten-minute ACE data on OASIS. 

For this purpose, we find that historical data for the most recent calendar year, updated 

once per year, should meet the need. This information is already collected and provided 

to NERC, through balancing area operators and reliability coordinators, so there should 

be minimal incremental burden associated with posting it on OASIS.

117. The Commission’s standard filing requirements, including opportunity for 

intervention and comment, address Morgan Stanley’s request to establish a process for 

market participants to challenge and resolve speed and accuracy assumptions. For 

example, as is the case in interconnection agreement proceedings, the transmission 

service agreement that reflects an individually negotiated self-supply arrangement for 

Regulation and Frequency Response service can be filed by the public utility 

transmission provider unexecuted. This will leave the transmission customer free to 

protest relevant aspects of the public utility transmission provider’s determination of 

whether the customer has made “alternative comparable arrangements,” including as 

those arrangements relate to the speed and accuracy of the customer’s proposed 

Regulation resources. 

118. With respect to Morgan Stanley’s request that public utilities demonstrate 

equivalent treatment for their own or their affiliate’s regulation requirements, we find that 

the increased transparency required by this Final Rule will accomplish this goal. The 

requirements adopted above apply to the public utility transmission provider’s own 
Docket Nos. RM11-24-000 and AD10-13-000 - 79 -

regulation resources, in the sense that it must apply the same procedures for determining 

regulation reserve requirements to itself as it does to self-supplying customers.

119. With respect to the request of TAPS that the Commission state explicitly that the 

NOPR’s proposal to account for the speed and accuracy of customer self-supplied 

regulating resources includes demand resources, we note that OATT Schedule 3, as 

amended by Order No. 890 makes clear that Regulation and Frequency Response service 

may be provided from non-generation resources capable of providing the service. 

Accordingly, a transmission provider’s determination of regulation reserve requirements 

should take into account the speed and accuracy characteristics of the resources in 

question, whether they are generation-based or otherwise. 

120. Turning to the various requests that the Commission step beyond the NOPR 

proposals, the Commission declines to require two-part pricing for regulation capacity 

and performance set forth in Order No. 755. We conclude that the requirements adopted 

above will allow customers and the Commission to ensure that the speed and accuracy of 

resources used for regulation reserves are properly taken into account in reserve level 

determinations within the context of the bilateral markets within which non-RTO/ISO 

public utility transmission providers operate. The Commission also declines commenter 

requests to provide incentive rate treatment for purchases of Regulation and Frequency 

Response service by public utility transmission providers to meet their OATT 

requirements. Commenters are not clear as to what mechanism they believe the 

Commission should use to require such treatment, and the Commission sees no reason to 

implement an incentives program in the context of ancillary services rate design. 
Docket Nos. RM11-24-000 and AD10-13-000 - 80 -

121. With respect to EEI’s comments regarding differences between primary frequency 

response and secondary frequency regulation, the Commission acknowledges these 

distinctions. Improving the transparency regarding the resources used to provide 

Regulation and Frequency Response service under OATT Schedule 3 does not alter the 

ability of any balancing authority to maintain adequate reserves to meet reliability 

requirements. The Commission thus sees no need to wait for the industry to better 

understand the relationship and interdependencies between primary and secondary 

frequency response prior to adopting the requirements of this final rule. The Commission 

will evaluate a public utility transmission provider’s compliance proposal as part of the 

case-by-case review discussed above, which will provide the public utility transmission 

provider the opportunity to demonstrate how it establishes its regulation reserve 

requirements.

C. Accounting and Reporting for Energy Storage Operations

122. In the NOPR, the Commission proposed to revise certain accounting and reporting 

requirements under its USofA and its forms, statements, and reports contained in Form 

Nos. 1, 1-F, and 3-Q. The Commission stated that the revisions were needed so that 

entities subject to the Commission’s accounting and reporting requirements could better 

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

utility operations. Moreover, the Commission noted that this information is important in 

developing and monitoring rates, making policy decisions, compliance and enforcement 

initiatives, and informing the Commission and the public about the activities of entities 

subject to the accounting and reporting requirements. 
Docket Nos. RM11-24-000 and AD10-13-000 - 81 -

123. The Commission proposed that new electric plant and associated O&M expense 

accounts be created to provide for the recording of investment and O&M costs of energy 

storage assets. The Commission also proposed to create a new purchased power account 

to provide for recording the cost of power purchased for use in storage operations. In 

addition, the Commission proposed that new Form Nos. 1 and 1-F schedules be created 

and existing schedules in the forms and Form No. 3-Q be amended to report operational 

and statistical data on storage assets. Finally, the Commission inquired about whether 

entities seeking to recover costs of energy storage assets and operations simultaneously 

under cost-based and market-based rates should be required to forego previously granted 

accounting and reporting waivers associated with market-based rates, and if so, should 

the requirement to forego the waivers be subject to some percentage threshold based on a 

ratio of cost-based cost recovery to total cost to be recovered.

124. While most commenters support the Commission’s proposal to revise the 

accounting and reporting requirements, there were several recommendations to make 

adjustments to the proposals and also requests for clarification of certain proposals. Only 

Solar Energy Association opposed the proposal, stating, without elaboration, that it 

believes it is premature to establish reporting requirements for energy storage.156 In the 

NOPR, the Commission responded to similar arguments regarding maturity of the energy 

storage industry as it relates to the use of energy storage assets to provide public utility 

 

156 Solar Energy Association Comments at 7. 
Docket Nos. RM11-24-000 and AD10-13-000 - 82 -

services, and found those arguments unconvincing.157 The Commission explained that 

there is a need for certainty in the accounting and reporting treatment for energy storage 

assets and operations, especially in instances where utilities seek to recover costs of 

energy storage operations in cost-based rates. Solar Energy Association has not provided 

new information that we could consider on this issue, therefore we find Solar Energy 

Association’s argument unconvincing. 

1. Electric Plant Accounts

Commission Proposal

125. In the NOPR, the Commission stated that the existing primary plant accounts do 

not explicitly provide for recording the cost of energy storage assets. The Commission 

concluded that this could lead to inconsistent accounting and reporting for these assets by 

utilities subject to the accounting and reporting requirements, making it difficult for the 

Commission and others to determine costs related to energy storage assets for cost-ofservice rate purposes. The Commission also noted that the lack of transparency affects 

interested parties,’ including the Commission’s, ability to monitor these utilities’ 

operations to prevent and discourage cross-subsidization between cost-based and marketbased activities. To address these issues, the Commission proposed to create electric 

 

157 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 71.
Docket Nos. RM11-24-000 and AD10-13-000 - 83 -

plant accounts in the existing functional classifications – production, transmission, and 

distribution – for new energy storage assets.158 

126. The Commission proposed that the installed costs of energy storage assets be 

recorded in the accounts based on the function or purpose the asset serves. On this basis, 

an asset that performs a single function will have its cost recorded in a single plant 

account. In instances where an energy storage asset is used to perform more than one 

function or purpose, the Commission proposed that the cost of the asset be allocated 

among the relevant energy storage plant accounts based on the functions performed by 

the asset and the allocation of the asset’s costs through cost-based rates that are approved 

by a relevant regulatory agency, whether federal or state.159 

Comments

127. In general, the commenters applaud the Commission’s efforts to improve 

transparency and prevent double-recovery of energy storage-related costs. The proposal 

to require utilities to record the costs of single-function energy storage assets in a single 

plant account garnered widespread support. However, the proposal to require utilities to 

allocate the costs of multi-function energy storage assets to the relevant energy storage 

plant accounts based on the functions performed and approved rate recovery, received 

 

158 Account 348, Energy Storage Equipment-Production; Account 351, Energy 

Storage Equipment-Transmission; and Account 363, Energy Storage EquipmentDistribution, respectively.

159 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 81.
Docket Nos. RM11-24-000 and AD10-13-000 - 84 -

comments supporting and opposing the proposal. Commenters that agree with the 

proposal generally indicate that the accounting would provide necessary transparency of 

a utility’s operations,

160 while commenters that oppose the proposal generally indicate 

that the accounting would place an undue administrative burden on utilities and is 

inconsistent with the Commission’s existing accounting rules.161 

128. Public Interest Organizations state that they support the development of 

requirements that can reveal the activities and costs of energy storage operations 

thorough greater transparency and detail. California PUC similarly states that in the 

event an energy storage developer intends to use a facility to perform multiple functions, 

the proposed accounting and reporting should provide transparency. NU Companies state 

that they support flexible rate treatment for energy storage assets and believe the 

proposed accounting will provide transparency required to guard against inappropriate 

cross subsidization of various services and double recovery cost. 

129. In opposition to the proposal, SDG&E contends that while it generally agrees with 

the Commission’s allocation “concept” to account for energy storage assets by functional 

category, i.e., production, transmission, and distribution, it is concerned that generally 

applicable financial tools may not be able to efficiently track or monitor up to three 

 

160 Public Interest Organizations Comments at 9-10; California PUC Comments at 

9; NU Companies Comments at 4; APPA Comments at 5; ESA Comments at 18-19; 

TAPS Comments at 28-29; and California Storage Association Comments at 11-12.

161 Southern California Edison Comments at 8; SDG&E Comments at 2-3; and 

EEI Comments at 29-30.
Docket Nos. RM11-24-000 and AD10-13-000 - 85 -

functional categories for one asset without increased and ongoing manual intervention.162 

SDG&E argues that it agrees that the initial allocation concept would capture expenses 

by each function as the Commission intends; however, if the utility subsequently changes 

its initial allocation in the future the proposed accounting would create an unnecessary 

administrative burden that if a mistake is made could result in costs of the asset being 

stranded. SDG&E contends that to ensure the asset is accounted for properly so that asset 

costs are not stranded, a utility would be required to continuously monitor the asset to 

make sure its initial allocation is consistent with the asset’s actual usage. SDG&E 

acknowledges that the NOPR addresses this concern;163 however, SDG&E asserts that 

there is a more straightforward approach that can be used to allocate the costs of a multifunction energy storage asset. SDG&E advocates, instead of using multiple plant 

accounts, that the cost of an energy storage asset be recorded in a single plant account 

and its cost allocated to the various functions it performs using current ratemaking 

methods.

130. Similar to SDG&E, Southern California Edison and EEI also complain of an 

increased administrative burden resulting from allocating an energy storage asset’s cost 

across multiple plant accounts as proposed in the NOPR. Southern California Edison and 

 

162 SDG&E Comments at 2-3.

163 SDG&E cites to the NOPR proposal that a utility transfer reallocated cost of an 

energy storage asset in accordance with the instructions of Electric Plant Instruction 

No. 12, Transfers of Property, 18 CFR Part 101 (2012). See SDG&E Comments at 3-4 

(citing to NOPR, FERC Stats. & Regs. ¶ 32,690 at P 82).
Docket Nos. RM11-24-000 and AD10-13-000 - 86 -

EEI contend that it would be necessary to create multiple unique property records for an 

energy storage asset to allocate its costs across multiple functions. Southern California 

Edison and EEI argue that having multiple records for each asset would require 

significant manual intervention while providing little practical value.164 Additionally, 

Southern California Edison and EEI assert, without providing any detail, that the NOPR 

proposal is inconsistent with the general principle that each asset should have a single 

record within an accounting system.165 Southern California Edison and EEI contend that 

there is neither a precedent for creating multiple property records for a single asset, nor a 

precedent for creating a record for a partial asset. Further, EEI argues that to the extent 

the different functions the cost of an energy storage asset could be spread across are 

subject to different depreciation rates, a single asset with a unique, individual economic 

life would be depreciated over multiple periods. 

131. EEI indicates that while it generally opposes the NOPR’s proposed accounting, it 

believes that in some circumstances the proposal may be a practical alternative for 

companies desiring to use it.166 Therefore, EEI advocates that utilities be afforded two 

options to account for energy storage assets that are used to perform multiple functions. 

 

164 Southern California Edison Comments at 8; and EEI Comments at 30.

165 Southern California Edison Comments at 8 and n 8 citing Definition No. 8 

Paragraph (A)(5), Continuing Plant Inventory Record, 18 CFR Part 101 (2012); and EEI 

Comments at 30.

166 EEI Comments at 29-31.
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EEI proposes that utilities be allowed to either: (1) record the costs of multi-function 

storage asset costs as proposed in the NOPR or (2) record the costs of the assets in a 

single plant account based on the primary function of the asset and to allocate costs to 

specific functions performed through the ratemaking process. Moreover, EEI 

recommends that the Form Nos. 1, 1-F, and 3-Q be amended to provide for reporting the 

option each company uses. EEI contends that allowing both options will afford 

companies the ability to maintain accounting and reporting records in the most efficient 

manner while providing transparency via reporting and uniformity in the ratemaking 

process. 

132. Southern California Edison supports EEI’s option (2). Southern California Edison 

and EEI contend that the option (2) approach is consistent with the approach used for 

certain assets that provide both state-jurisdictional and FERC-jurisdictional functions.167 

Southern California Edison and EEI explain that the ratemaking process may include a 

formula or special study in order to appropriately allocate the costs across functions.

Commission Determination

133. SDG&E’s, Southern California Edison’s, and EEI’s arguments that requiring 

utilities to allocate the costs of energy storage assets that perform multiple functions 

across the relevant energy storage plant accounts places an undue administrative burden 

on utilities are unpersuasive. These commenters generally argue that this perceived 

 

167 Southern California Edison Comments at 8; and EEI Comments at 31-32.
Docket Nos. RM11-24-000 and AD10-13-000 - 88 -

undue administrative burden results from a requirement that utilities maintain records that 

track the usage of energy storage assets and costs associated with such use. However, 

utilities would be required to maintain records with this information whether accounting 

for the costs of an asset in multiple accounts as proposed in the NOPR or accounting for 

the costs in a single account as proposed by SDG&E, Southern California Edison and 

EEI. For example, information on the allocation of the cost of an energy storage asset to 

a particular function will have to be maintained by utilities operating multi-function, 

multi-cost recovery energy storage assets, regardless of whether the information is 

required to be reported in the reporting forms as proposed in the NOPR or if the 

information is not reported in the forms yet is used in ratemaking determinations as 

proposed by SDG&E, EEI, and Southern California Edison. Because utilities with 

energy storage operations that recover any portion of costs on a cost-of-service basis will 

be required to maintain use and cost allocation information on the assets, requiring these 

utilities to implement the NOPR’s accounting proposal does not result in an additional

burden on utilities that could be considered unduly burdensome. 

134. Moreover, SDG&E’s argument that costs could possibly be stranded if a utility 

does not appropriately account for energy storage operations is also unconvincing. This 

possibility exists throughout the utility industry and is not uniquely attributable to 

utilities with energy storage operations. Administrative errors, such as errors in 

accounting, that lead to costs being stranded due to inadequate or insufficient internal 

controls over policies, practices, and procedures used to track costs associated with assets 

represent a risk for all utilities whether or not the utilities own energy storage assets. 
Docket Nos. RM11-24-000 and AD10-13-000 - 89 -

Risks of this nature are inherent to all utilities’ operations. Utilities must maintain 

adequate, sufficient, and reliable internal controls to reduce the probability of this risk 

affecting operations.

135. As support for their argument that the NOPR’s proposed accounting causes an 

undue administrative burden and that their advocated accounting avoids the burden, 

Southern California Edison and EEI contend that their proposal to record the costs of an 

energy storage asset in a single plant account could require utilities to implement a 

formula or special study to appropriately allocate the costs of the asset across multiple 

functions. However, this contention does not support their argument. A formula or 

special study would require utilities to maintain the same information on the functions 

performed by an energy storage asset and costs associated with such performance, as 

would be required by the NOPR’s proposed accounting. Thus, a formula or special study 

would not avoid the administrative burden associated with accounting for energy storage 

assets and operations. Furthermore, Southern California Edison and EEI have not 

provided information to support a determination that the burden would be decreased by 

implementing their proposed accounting. Their proposal would result in less transparent 

reporting of information on energy storage operations as compared to the NOPR’s 

proposed accounting. 

136. While the commenters argue that the accounting proposal might require increased 

manual intervention to account for and report storage assets, it is not clear that such 

intervention, if any, results in an undue administrative burden. As the Commission 

observed in the NOPR, uniform, transparent, and consistent reporting of information on 
Docket Nos. RM11-24-000 and AD10-13-000 - 90 -

energy storage operations by utilities is essential, especially by those seeking to recover 

costs of energy storage services in cost-based rates.168 We believe that adopting the 

NOPR’s proposed accounting and reporting revisions will improve transparency.169 The 

revisions will enhance the Commission’s and other form users’ ability to make a 

meaningful assessment of a utility’s cost-of-service rates, and will provide for better 

monitoring for cross-subsidization. In instances where an energy storage asset performs 

multiple functions, it is imperative that costs associated with each function be transparent 

and allocable to the function performed so that cross-subsidization of costs can be 

prevented. SDG&E, EEI, and Southern California Edison have not provided information 

that would refute the Commission’s determination in the NOPR that the accounting 

proposal is not overly burdensome. 

137. EEI’s recommendation that utilities be afforded two options to account for and 

report storage assets that provide multiple services and recover associated costs 

simultaneously under cost-based and market-based rate methods is not consistent with the 

intent of the NOPR’s proposed accounting and reporting revisions. The NOPR proposed

one method to account for energy storage assets performing multiple functions under 

multiple cost recovery mechanisms to ensure that utilities account for the assets on a 

uniform and consistent basis. EEI’s proposal for two methods of accounting could result 

 

168 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 71.

169 Id. P 72.
Docket Nos. RM11-24-000 and AD10-13-000 - 91 -

in similarly-situated utilities with energy storage assets reporting the same type of 

transaction differently. This would not provide the uniformity sought by the accounting 

and reporting proposals and could disrupt consistency, which would make it difficult to 

compare utilities with energy storage operations across the industry. In addition, 

adopting EEI’s proposal to record the costs of the assets in a single account would reduce 

the transparency of information reported in the forms. This information is critical to the 

clarity and transparency needed to support a reasonable analysis of a utility’s cost. 

Consequently, we will not adopt EEI’s proposal. 

138. Southern California Edison’s assertion that the NOPR requirement adopted here is 

not consistent with Definition No. 8, Continuing Plant Inventory Record, is incorrect.170 

While the definition pre-dates the NOPR’s accounting and reporting requirements, the 

definition is broad enough such that its premise is as relevant for energy storage assets as 

it is for conventional electric plant assets. The accounting and reporting proposals 

require utilities to maintain a detailed record of the descriptive operational and cost 

information associated with energy storage assets consistent with the provisions of 

Definition No. 8. 

139. Further, Southern California Edison’s and EEI’s contentions that there is no 

precedent for creating multiple property records for a single or partial asset misconstrues 

the proposed accounting and reporting requirements. The accounting and reporting 

 

170 18 CFR Part 101 (2012).
Docket Nos. RM11-24-000 and AD10-13-000 - 92 -

proposals we adopt here do not require utilities to maintain multiple records for a single 

or partial asset as Southern California Edison and EEI contend. Rather, the reforms

maintain the existing requirement of Definition No. 8 that utilities maintain descriptive 

operational and cost information on each asset. Moreover, we do not consider allocating 

the cost of a single asset to multiple property accounts to be the same as creating multiple 

property records as though there were multiple assets. A utility can maintain information 

on a single energy storage asset with costs allocated to multiple plant accounts in a single 

record that provides descriptive operational and cost information on the asset. 

Additionally, in accordance with General Instruction No. 12, Records for Each Plant, 

utilities are required to maintain a record, by electric plant accounts, on the book costs of 

each plant owned.171 The requirement to record the cost of a multi-function, multi-cost 

recovery energy storage asset to more than one plant account is consistent with this 

instruction.

140. EEI argues that if different depreciation rates are applied to a single energy storage 

asset in accordance with each function the asset performs the various allocated costs of 

the asset would be depreciated over multiple periods. EEI is correct that there is a 

possibility of this occurring if costs of a single asset were subjected to multiple differing 

depreciation rates. However, this has neither been the experience of this Commission nor 

 

171 The instructions indicate that the term “plant” means each generating station 

and each transmission line or appropriate group of transmission lines. This term is also 

applicable to energy storage facilities. 18 CFR Part 101 (2012).
Docket Nos. RM11-24-000 and AD10-13-000 - 93 -

do we expect that a utility’s primary rate regulator would subject a single asset to 

multiple depreciation rates. Although the costs of an energy storage asset may be 

allocated across multiple plant accounts, we agree with EEI that the asset is a single 

unique asset with a single economic life. Thus, there should be a single depreciation rate 

applied to the asset that allocates in a systematic and rational manner the service value of 

the asset over its service life. To the extent possible, a utility should apply a single 

depreciation rate to an energy storage asset. 

141. The reforms adopted here are designed to provide needed transparency, but also to 

reflect a fair balance between the need for information and the additional burden on the 

utility. We believe these accounting reforms for energy storage reflect this balance. 

Accordingly, Account 348, Energy Storage Equipment-Production, Account 351, Energy 

Storage Equipment-Transmission, and Account 363, Energy Storage EquipmentDistribution, as proposed in the NOPR are adopted in this Final Rule.

2. Power Purchased Account

Commission Proposal

142. In the NOPR, the Commission noted that to provide some electrical services, 

energy storage devices may need to maintain a particular state of charge, or as in the case 

of compressed air facilities, may need to maintain some minimum pressure, and that 

some companies may be required to purchase power to maintain a desired state of charge 

or pressure. Further, the Commission determined that the benefits of enhanced 

transparency, in this instance, resulting from having the cost of power purchased for 

energy storage operations reported separately from other power purchases, outweighs the 
Docket Nos. RM11-24-000 and AD10-13-000 - 94 -

associated burden of requiring the accounting. Therefore, the Commission proposed a 

new Account 555.1, Power Purchased for Storage Operations, to report the cost of: 

(1) power purchased and stored for resale; (2) power purchased that will not be resold but 

instead consumed in operations during the provisioning of services; (3) power purchased 

to sustain a state of charge; and (4) power purchased to initially attain a state of charge, 

with item 4 being capitalized as a component cost of initially constructing the asset. 

Comments

143. Most commenters support the proposed accounting. For example, ESA and others 

state that the new account will enhance the transparency of reporting the operations of 

storage resources.172 Hydro Association indicates that similar accounting should be 

established for the cost of power purchased for pumped storage operations to account for 

initial unit testing and commissioning.173 

144. Hydro Association states, in particular, for closed-loop pumped storage projects, 

the first unit testing entails pumping or charging the upper reservoir. Hydro Association 

explains that at an early stage of development of a pumped storage project, the generating 

station is months away from being declared “commercial” and testing the station requires 

energy from the grid to initially attain a fully charged state (i.e., a full upper reservoir). 

Hydro Association argues that these initial charging costs should be capitalized. Further, 

 

172 ESA Comments at 21-22.

173 Hydro Association Comments at 12-13.
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Hydro Association contends that costs incurred to test the generating station should 

likewise be capitalized into the cost of the project. In contrast to Hydro Association’s 

assertion that the existing accounting requirements for pumped storage operations are not 

sufficient, EEI argues that the existing requirements appropriately and transparently 

provide for pumped storage plants.174 

Commission Determination

145. We will adopt the new Account 555.1, Power Purchased for Storage Operations, 

as proposed in the NOPR. The accounting reforms here requiring initial charging and 

testing costs to be capitalized seek to apply existing requirements for conventional 

electric plant, such as pumped storage plant, to new energy storage assets. The 

requirements do not seek to differentiate the accounting for new energy storage assets 

from pumped storage plant in this instance. 

146. We disagree with Hydro Association’s assertion that the existing accounting 

requirements for pumped storage operations are not sufficient. Contrary to Hydro 

Association’s assertion, pumped storage is not prohibited, for accounting purposes, by the 

existing accounting rules and regulations from capitalizing costs incurred to initially 

bring a pumped storage facility into operation nor is it prohibited from capitalizing costs 

incurred to test pump storage facilities prior to commercial operation. Electric Plant 

Instruction No. 3, Components of Construction Cost, provides that expenses incidental to 

 

174 EEI Comments at 27.
Docket Nos. RM11-24-000 and AD10-13-000 - 96 -

the construction of plant such as cost to initially attain a fully charged state to bring the 

plant into operation may be capitalized as a component cost of the plant.175 Further, 

Electric Plant Instruction No. 9, Equipment, provides that the costs of plant shall include 

necessary costs of testing or running plant or parts thereof during the test period prior to 

the plant becoming ready for or being placed in service.176 Consequently, we agree with 

EEI’s statement that the existing accounting requirements for pumped storage are 

sufficient. The NOPR proposals for Account 555.1 are adopted in this Final Rule as 

proposed. 

3. Operation and Maintenance Expense Accounts

Commission Proposal

147. In the NOPR, the Commission observed that there are O&M expenses related to 

the use of energy storage assets to provide utility services, and there are no existing O&M 

expense accounts in the USofA specifically dedicated to accounting for the cost of energy 

storage operations. Therefore, the Commission proposed new O&M expense accounts 

for energy storage-related O&M expenses that are not specifically provided for in the 

existing O&M expense accounts in the USofA and revision of certain existing O&M 

expense accounts. Specifically, the Commission proposed that energy storage expenses 

be recorded in Account 548.1, Operation of Energy Storage Equipment, and Account 

 

175 18 CFR Part 101 (2012).

176 Id. 
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553.1, Maintenance of Energy Storage Equipment, for energy storage plant classified as 

production; Account 562.1, Operation of Energy Storage Equipment, and Account 570.1, 

Maintenance of Energy Storage Equipment, for energy storage plant classified as 

transmission; and Account 582.1, Operation of Energy Storage Equipment, and Account 

592.2, Maintenance of Energy Storage Equipment, for energy storage plant classified as 

distribution, to the extent that the existing O&M expense accounts do not adequately 

support recording of the cost.177 

Comments

148. The commenters support the proposed O&M expense accounts. Most commenters 

state that the proposed accounts will provide sufficient transparency of energy storagespecific O&M expenses.178

Commission Determination

149. This Final Rule adopts the NOPR proposals for the O&M expense accounts with 

the exception that the account number for Account 582.1 will be changed to Account 

584.1. The name and text of the account will remain as proposed in the NOPR.

150. In addition, the NOPR proposed that the text of Account 592, Maintenance of 

Station Equipment (Major only), and Account 592.1, Maintenance of Structures and 

Equipment (Nonmajor only), be revised such that the accounts do not provide for O&M 

 

177 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 96.

178 See, e.g., ESA Comments at 22; Beacon Power Comments at 21-22; and 

California Storage Alliance Comments at 17.
Docket Nos. RM11-24-000 and AD10-13-000 - 98 -

expenses related to energy storage operations and also to remove the reference to 

Account 363. Accordingly, the following text is struck from Accounts 592 and 592.1:

“and account 363, Storage Battery Equipment.”

4. New and Amended Form Nos. 1, 1-F, and 3-Q Schedules

Commission Proposal

151. In the NOPR, the Commission acknowledged that the existing schedules in the 

Form Nos. 1, 1-F, and 3-Q do not provide for reporting information on new types of 

energy storage assets such as batteries and flywheels.179 Consequently, the Commission 

proposed to amend several schedules of the Form Nos. 1, 1-F, and 3-Q to include energy 

storage plant, purchased power, and O&M expense accounts.180 In addition, the 

Commission proposed to add new schedule pages 414-416, Energy Storage Operations 

(Large Plants), and pages 419-420, Energy Storage Operations (Small Plants), to the 

Form Nos. 1 and 1-F to provide for reporting operational and statistical information on 

new types of energy storage assets.181 The Commission proposed that filers with energy 

storage assets having a rated capacity of 10,000 kilowatts (KW) or more record the 

 

179 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 101.

180 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 106; and Appendix B Proposed 

Amendments to Form Nos. 1, 1-F and 3-Q.

181 The text of the NOPR indicated that the schedules pages were 414-417 and 

419-421 for the respective Large and Small Plant schedules. However, the proposed 

schedules included in Appendix B of the NOPR used different page numbers. We clarify 

that the schedule page numbers are 414-416 and 419-420, for the respective Large and 

Small Plant schedules, as indicated in this Final Rule.
Docket Nos. RM11-24-000 and AD10-13-000 - 99 -

operations of the assets on schedule pages 414-416, and filers with energy storage assets 

with less than 10,000 KW of capacity record the operations on schedule pages 419-420. 

In addition, the Commission sought comment on whether 10,000 KW is an appropriate 

threshold for requiring utilities to report more detailed plant and cost information for 

energy storage plant.

182

 The Commission noted that certain existing schedules in the 

Form No. 1 have a 10,000 KW threshold.183 However, the Commission opined that this 

threshold may not be appropriate for new energy storage assets that in many instances 

may be rated below 10,000 KW. 

Comments

152. Most commenters support the NOPR’s forms proposals, and a few commenters 

recommend revisions to the forms in addition to those proposed.184 Consistent with its 

recommendation that the Commission implement two options to account for energy 

storage assets, EEI proposes that the forms provide for disclosing the specific option a 

 

182 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 103.

183 See Form No. 1, schedule pages 408-409, Generating Plant Statistics (Large 

Plants) and schedule pages 410-411, Generating Plant Statistics (Small Plants). Schedule 

pages 408-409 require filers to report more detailed information for generating assets 

with a rated capacity of 10,000 KW or more than schedule pages 410-411, which require 

less detailed information for generating assets with a rated capacity of less than 10,000 

KW.

184 See, e.g., APPA Comments at 5; Beacon Comments at 22-23; California 

Storage Alliance Comments at 19; and ESA Comments at 23. 
Docket Nos. RM11-24-000 and AD10-13-000 - 100 -

utility is using to account for the assets.185 However, because we are not adopting EEI’s 

recommendation for two accounting options, its disclosure proposal is unnecessary as 

utilities will have one uniform method for accounting for energy storage assets. 

153. Hydro Association contends that there are shortcomings in the way the Form No. 1 

treats existing pumped storage plants, as they are now used, and it suggests modifications 

that it believes will improve reporting of information on the assets. Hydro Association 

recommends that the heading of Line 6 “Plant Hours Connect to Load While Generating” 

of schedule pages 408-409, Pumped Storage Generating Plant Statistics (Large Plants), in 

the Form No. 1 be changed to read “Plant Hours Connect to Load.”186 Hydro Association 

reasons that the total hours a facility is synchronized and connected to the grid are 

important to identify. Hydro Association explains that a facility’s effectiveness is based 

on its total utilization factor, which Hydro Association describes as the sum of hours 

generating, pumping, and condensing. Hydro Association asserts that this sum should be 

reported on Line 6 under its proposed heading. Alternatively, Hydro Association proffers 

that if further detail is needed, the heading of Line 6 can remain as is and two new line 

items can be added to the schedule to report pumping and condensing hours. 

154. Further, Hydro Association also contends that Line 38, “Expenses for KWh (line 

37/9)” incorrectly calculates the cost per kilowatt hour (KWh) of pumped storage 

 

185 EEI Comments at 5.

186 Hydro Association Comments at 11.
Docket Nos. RM11-24-000 and AD10-13-000 - 101 -

operations.

187

 Hydro Association asserts that the calculation should include energy 

generated and energy used for pumping operations. Hydro Association proposes that 

Line 38 be revised to read as “Expenses for KWh (line 37/9+10).”

155. TAPS recommends revisions to new schedule pages 414-416, Energy Storage 

Operations (Large Plants).188 TAPS observes that the instruction for column heading 

(l) refers to “revenues from energy storage operations” while the name of the column is 

“Revenues from the Sale of Stored Energy.” TAPS asserts that because revenues from 

energy storage operations can be garnered by means other than from energy sales, the 

name of the column should be revised to be consistent with the instructions of the column 

or additional columns should be created, with corresponding instructions, to report other 

types of revenues. 

156. In regard to the 10,000 KW threshold, California Storage Alliance states that it 

believes 10,000 KW is an appropriate threshold for requiring a difference in the reporting 

requirements for the assets.189 In contrast, Beacon and ESA recommend a higher 

threshold of 20,000 KW.190 Beacon and ESA assert that this threshold would align with 

the Small Generator Interconnection threshold and the capacity value for many existing 

and planned energy storage assets. 

 

187 Id.

188 TAPS Comments at 28-29.

189 California Storage Alliance Comments at 19.

190 Beacon Comments at 22; and ESA Comments at 22-23.
Docket Nos. RM11-24-000 and AD10-13-000 - 102 -

Commission Determination

157. We generally agree with the premise of Hydro Association’s contention that Line 

6 of schedule pages 408-409 could benefit from additional detail. However, the cost of 

additional detail must be weighed against any associated benefit that could result. To this 

end, we strive to achieve a balance such that the cost of implementing new reporting 

requirements does not excessively exceed the benefits of implementation. A particularly 

important benefit to the Commission of additional detail is that it provides data necessary 

for the regulation and review of companies’ operations. Hydro Association has neither 

explained how information on pumping and condensing hours is needed for the 

regulation and review of pumped storage operations nor has it explained how the 

information would be beneficial for other uses. Hydro Association indicates that this 

information will provide for a measure of a facility’s effectiveness, however, it is not 

clear that the cost of requiring this information is on par with any perceived benefits or 

that the requirement would not be overly burdensome. Consequently, we will not adopt 

Hydro Association’s proposal to include the sum of generating, condensing and pumping 

on Line 6, nor will we adopt its alternate proposal to add two new line items to the 

schedule. 

158. With regard to Hydro Association’s contention that Line 38 of schedule pages 

408-409 incorrectly calculates the cost per KWh of pumped storage operations, this line 

is not intended to report this cost, rather it is intended to report the cost per KWh of 

energy generated and transmitted to the grid. Line 38 of the schedule includes a formula 

that requires filers to divide total production expenses reported on Line 37 by energy 
Docket Nos. RM11-24-000 and AD10-13-000 - 103 -

generated and transmitted to the grid reported on Line 9. Nevertheless, we recognize 

Hydro Association’s underlying concern that, as a conforming change given the other 

accounting requirements in this Final Rule, the schedule should report this information, 

including the energy generated and energy used in pumping, as illustrated in the formula 

example submitted by Hydro Association – Line 37/9+10. 

159. We agree that reporting this information on schedule pages 408-409 will help

create a more accurate database for benchmarking and O&M cost studies, and this 

information also will assist interested parties’, including the Commission’s, review of the 

operations of pumped storage facilities across the industry. We note that the data inputs 

needed to perform the calculation are currently required to be reported on Lines 9, 10 

and 37 of schedule pages 408-409, so this requirement is not wholly new and the burden 

on utilities to calculate and report the information specifically on schedule pages 408-409

is minimal. Accordingly, the item on Line 38 of schedule pages 408-409 is revised to 

read “Expenses per KWh of Generation (line 37/line 9)” and a new Line 39 is added 

which reads “Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10)).”

160. TAPS asserts that revenues from energy storage operations can originate from 

activities other than energy sales, thus it recommends that proposed schedule pages 414-

416 be revised to provide for other types of revenues. We agree that there are potentially 

other activities that energy storage operators can engage in to generate revenue. For 

example, as TAPS noted, an energy storage operator can conceivably earn revenues from 

the sale of storage capacity. While we are not aware of any instances where these types 

of storage capacity transactions have occurred, to ensure that the schedule provides 
Docket Nos. RM11-24-000 and AD10-13-000 - 104 -

adequate flexibility to allow for the reporting of all revenues from energy storage 

operations we will revise the name of the column to read “Revenues from Energy Storage 

Operations.” We will not create additional columns to report the various types of 

revenue because the instructions to the schedule already require filers to disclose this 

information in a footnote. 

161. Beacon and ESA recommend that the Commission align the threshold for detailed 

reporting in the new schedules with the existing 20,000 KW threshold established in 

Order No. 2006 for the interconnection of small generators.191 To this end, Beacon and 

ESA propose a 20,000 KW threshold as opposed to the 10,000 KW proposed in the 

NOPR. However, the 20,000 KW threshold in Order No. 2006 was established 

notwithstanding the requirement that small generators having 10,000 KW or more but 

less than 20,000 KW that are subjected to the Commission’s accounting and reporting 

requirements would be subjected to a higher reporting burden than companies with 

generators of less than 10,000 KW. In this instance, the Commission determined that 

while there is a need to further remove barriers to participation in energy markets by 

establishing terms and conditions under which public utilities must provide 

interconnection service, there is also a parallel need for detailed information on the 

 

191 Standardization of Small Generator Interconnection Agreements and 

Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180, order on reh 'g, Order 

No. 2006-A, FERC Stats. & Regs. ¶ 31,196 (2005), order on clarification, Order 

No. 2006-B, FERC Stats. & Regs. ¶ 31,221 (2006). This order originally set forth the 

terms and conditions under which public utilities must provide interconnection service to 

Small Generating Facilities of no more than 20,000 KW.
Docket Nos. RM11-24-000 and AD10-13-000 - 105 -

activities and operations of companies using these assets in the provisioning of utility 

services. Thus, the Commission maintained its existing 10,000 KW threshold for these 

small generators.

162. Beacon and ESA have not provided information that supports a decreased 

reporting burden for energy storage assets over 10,000 KW as compared to the reporting 

burden of conventional assets that are currently subject to the 10,000 KW threshold. Nor 

has Beacon or ESA provided information that would support increasing the existing 

10,000 KW threshold for conventional assets to maintain parity between those assets and 

energy storage assets. Their proposal may result in an unduly discriminatory reporting 

requirement for energy storage assets compared to conventional assets, therefore we will 

not adopt the recommended 20,000 KW reporting threshold. 

163. We will adopt the NOPR’s proposed 10,000 KW threshold as this amount is 

neither unduly conservative nor is it overly burdensome. As we indicated in the NOPR, 

information that would be reported for energy storage assets and operations differs little 

from other data public utilities maintain under the USofA.192 If a utility owns and 

operates these energy storage assets, reporting information on them in the proposed 

accounts and FERC form schedules should not be burdensome. 

 

192 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 73.
Docket Nos. RM11-24-000 and AD10-13-000 - 106 -

164. Finally, we will amend schedule pages 2-4, 204-207, 320-323, 324a-324b, 326-

327, 397, and 401a of the Form Nos. 1, 1-F, and 3-Q as proposed in the NOPR.193 We 

note that these amendments include revising schedule page 401a, Electric Energy 

Account, of the Form No. 1 to change the title of line item 10 to “Purchases (other than 

for Energy Storage)” and add a new line item 11 “Purchases for Energy Storage” to 

provide for reporting power purchased for energy storage operations. These changes 

require an additional line item on Form No. 1 schedule page 401a to provide for reporting 

stored energy because total net sources of energy must equal total disposition of energy 

as instructed by the requirement on Line 30 of the schedule. Utilities with energy storage 

operations that have stored energy as of the reporting date of the form must report the 

amount by megawatt hour in the schedule so that total net sources of energy is equal to 

total disposition of energy reported. Accordingly, as a conforming change, a new line 

item titled “Total Energy Stored” will be added to schedule page 401a under the heading 

“Disposition of Energy.” 

 

193 NOPR, FERC Stats. & Regs. ¶ 32,690 at Appendix B Proposed Amendments 

to Form Nos. 1, 1-F, and 3-Q.
Docket Nos. RM11-24-000 and AD10-13-000 - 107 -

5. Other Accounting and Reporting Issues

a. Existing Waivers of Accounting and Reporting 

Requirements

Commission Proposal

165. In the NOPR, the Commission proposed that public utilities currently providing 

jurisdictional services and recovering costs of the services under market-based rates that 

have been granted waiver of the accounting and reporting requirements and that seek 

recovery of a portion of service costs under cost-based rates, be required to forego the 

previously issued waivers and account for and report all cost and operational information 

to the Commission in accordance with its accounting and reporting requirements.194 In 

addition, the Commission also inquired whether there should be a percentage of cost 

recovery threshold or other determining factor that triggers the accounting and reporting 

obligations in this situation, or should any instance of multiple cost recovery, regardless 

of the percentage of a utility’s total costs, trigger the accounting and reporting 

obligations. 

Comments

166. Most commenters agree with the proposal to rescind previously issued waivers 

and many of these commenters argue that there should not be a percentage threshold that 

triggers the requirement. California Storage Alliance states that rescinding the waivers 

will enhance transparency and facilitate development and monitoring of the cost-based 

 

194 Id. P 75.
Docket Nos. RM11-24-000 and AD10-13-000 - 108 -

portion of rates.195 Further, California Storage Alliance states that there should not be a 

percentage threshold that triggers accounting and reporting requirements. California 

Storage Alliance, and others,196 also recommend that in instances where a competitive 

solicitation process is used to determine recovery of the cost-based portion of rates, a 

public utility should not be required to forego any reporting and accounting waivers. In 

further describing their position, these commenters suggest that a particular “storage asset 

may be capable of simultaneously providing two distinct functions, one traditionally costbased use, and another generally market-based.” They then posit the possibility of a 

public utility issuing a competitive solicitation solely for the “cost-based use.” Their 

comments then assert that the winning bidder would be obligated to provide the “costbased service” and would be paid through a “rate-based mechanism.”

197

 We also 

received requests to clarify that the waivers will only be rescinded if energy storage is 

involved.198 

Commission Determination

167. We will adopt the NOPR proposal requiring public utilities to forego previously 

issued accounting and reporting waivers in instances where the utility seeks to recover 

 

195 California Storage Alliance Comments at 10.

196 California Storage Alliance Comments at 10-11; ESA Comments at 18; and 

Beacon Comments at 18.

197 Id.

198 Indicated Suppliers Comments at 6 -11; EPSA Comments at 13; and EEI 

Comments at 33-34. 
Docket Nos. RM11-24-000 and AD10-13-000 - 109 -

costs associated with operation of an energy storage asset simultaneously under marketbased and cost-based rate recovery mechanisms. We will not impose a percentage 

recovery threshold, therefore any cost-based recovery of the cost will trigger rescission of 

previously granted accounting and reporting waivers. 

168. Regarding the comments of California Storage Alliance, ESA, and Beacon, the 

Commission clarifies that sellers under a competitive solicitation that meets the 

requirements of this Final Rule199 will not be required to forego any prior accounting and 

reporting waivers. However, we feel it necessary to explain that the reason for this 

outcome differs from what these commenters seem to propose. 

169. Their comments seem to indicate a belief that there are some products that are 

inherently cost-based and others that are inherently market-based, and that if a 

competitive solicitation were held for a cost-based product, the resulting rates would still 

be cost-based. We are not persuaded by these commenters' arguments that products 

should be classified as inherently cost-based or market-based. Some potential sellers of 

these products will qualify to sell them at market-based rates because they either lack 

market power in the relevant product market, or it has been adequately mitigated. Other 

sellers who do not qualify to make market-based sales, because they either have market 

power or cannot prove they lack it, will be limited to charging cost-based rates. 

 

199 See supra PP 87-90.
Docket Nos. RM11-24-000 and AD10-13-000 - 110 -

170. Under the competitive solicitation proposal at bar, proof that the competitive 

solicitation meets the requirements of this Final Rule will demonstrate that a seller 

qualifies to make market-based sales at the rates resulting from the solicitation, and thus 

can avoid having to justify those rates on a cost-of-service basis. Because such sellers 

will still only be making market-based sales, there is no reason to rescind the prior 

accounting and reporting waivers that were granted because they would only be making 

market-based rate sales. Cost-based sales of ancillary services have always been an 

option for third party sellers, and remain an option for them after issuance of this Final 

Rule. However, all of the requirements of cost-of-service regulation, such as the very 

accounting and reporting requirements at issue here, would apply to such sales. We also 

clarify that the requirement for a company to forego previously issued accounting and 

reporting waivers, in this instance, is only applicable when energy storage is involved. 

There may be other occasions when previously issued waivers may be rescinded however 

those occasions are outside the scope of this rulemaking. 

b. Definition of Energy Storage Asset or Technology

171. EEI asks that the Commission clarify the definition of energy storage assets or 

technologies that are subject to these accounting and reporting requirements.200 EEI 

proposes that the Commission define energy storage assets as “commercially available 

technology that is capable of absorbing energy, storing energy, and subsequently 

 

200 EEI Comments at 26-28.
Docket Nos. RM11-24-000 and AD10-13-000 - 111 -

releasing the energy to the electric system.”201 Further, EEI states that certain other 

energy storage assets should be exempted from the Final Rule, and thus the new 

accounts, if the function of the asset is so clearly related to activities properly reflected in 

existing accounts such that the asset is not designed to be used as an “energy storage 

asset” under the definition articulated in this Final Rule. EEI states, for example, that the 

following assets or technologies should be exempted:

Batteries used primarily in connection with the control and 

switching of electric energy produced and the protection of 

electric circuits and equipment that are recorded in the 

following existing FERC accounts: 

Account 315, Accessory Electric Equipment 

Account 324, Accessory Electric Equipment 

(Major Only)

Account 345, Accessory Electric Equipment 

Batteries used in connection with controlling station 

equipment or for general station purposes that are recorded in 

the following existing FERC account: 

Account 353, Station Equipment 

Batteries used in connection with controlling station 

equipment or for general station purposes that are recorded in 

the following existing FERC account: 

Account 362, Station Equipment 

Compressed air systems used for pneumatic or air tools that 

are recorded in the following existing FERC accounts: 

Account 316, Miscellaneous Power Plant Equipment 

 

201 Id.
Docket Nos. RM11-24-000 and AD10-13-000 - 112 -

Account 325, Miscellaneous Power Plant Equipment 

(Major Only)

Account 346, Miscellaneous Power Plant Equipment

Commission Determination

172. We agree with EEI that there are certain assets that are excluded from the scope of 

this Final Rule, however, we will not adopt EEI’s proposed definition for an energy 

storage asset or technology. The definition is too broad and could be interpreted to 

include storage-type technologies that are outside the scope of this Final Rule. As EEI 

indicated, the assets listed above are the type of assets that should be excluded. This list 

is not exhaustive; rather it is an example of the type of assets and activities served by 

those assets that are a baseline indicator of assets that are outside the scope of the 

accounting and reporting requirements adopted in this Final Rule. For the purposes of 

this Final Rule, an energy storage asset shall be defined as property that is interconnected 

to the electrical grid and is designed to receive electrical energy, to store such electrical 

energy as another energy form,202 and to convert such energy back to electricity and 

deliver such electricity for sale, or to use such energy to provide reliability or economic 

benefits to the grid. The term may include hydroelectric pumped storage and compressed 

air energy storage, regenerative fuel cells, batteries, superconducting magnetic energy 

 

202 Electrical energy may be converted to and stored as several different forms of 

energy such as chemical, mechanical, and thermal energies.
Docket Nos. RM11-24-000 and AD10-13-000 - 113 -

storage, flywheels, thermal energy storage systems, and hydrogen storage, or 

combination thereof, or any other technologies as the Commission may determine.203 

c. Incorporating Energy Storage Plant Accounts into 

Existing Formula Rates

173. EEI requests that the Commission pre-authorize inclusion of the new energy 

storage plant and O&M expense accounts in existing formula rates without the need for 

separate, company-specific section 205 proceedings.204 EEI contends that many 

jurisdictional utilities that own and operate energy storage technologies account for the 

assets in existing accounts that are incorporated in formula rates. EEI states that to the 

extent the new accounts require a revision to existing filed rates, the Commission should 

allow such changes to be filed in a compliance filing in this proceeding. 

Commission Determination

174. We agree with EEI that utilities currently owning and operating these assets are 

using existing accounts and reporting schedules. Moreover, in many instances these 

accounts are incorporated in the companies’ formula rate templates and costs reported in 

the accounts are through operation of the formula rate included in rate determinations. 

For some of these companies, transferring amounts from an existing plant account under 

 

203 Although hydroelectric pumped storage is an energy storage technology in 

accordance with our definition, the accounting and reporting requirements of this 

rulemaking do not apply to the assets, notwithstanding the revisions to schedule pages 

408-409. As we indicated previously, our existing accounting and reporting requirements 

for pumped storage sufficiently accommodate pumped storage assets and operations.

204 EEI Comments at 32-33.
Docket Nos. RM11-24-000 and AD10-13-000 - 114 -

a particular functional classification to a new energy storage plant account under the 

same functional classification may involve a relatively straight-forward transfer of cost. 

In this type of situation, a compliance filing will provide adequate transparency to allow 

interested parties, including the Commission, to review amounts being transferred from 

one account to another and also to establish the incorporation of the new energy storage 

plant and O&M expense accounts in the formula rate tariff. However, a compliance 

filing may not be suitable for all situations. 

175. For example, in instances where a company intends on recording the costs of an 

energy storage asset to multiple plant accounts in accordance with a plan to support 

multiple functions using the asset, a compliance filing may not provide for an adequate 

review of the many variables involved that can impact the determination of the 

appropriate allocation of the cost and rates charged based on the allocation. Moreover, if 

a company intends on recovering capital and O&M costs of the asset simultaneously 

under cost-based and market-based rate recovery mechanisms, a compliance filing would 

not provide sufficient notice or review of the cost to be recovered under the two rate 

mechanisms. Consequently, because a compliance filing is not appropriate for all 

situations, we will limit approval of its use to companies that are transferring amounts 

from an existing plant account under a particular functional classification to a new energy 

storage plant account under the same functional classification. Transfers of the costs to 

other plant accounts after this initial compliance filing shall be subject to the 
Docket Nos. RM11-24-000 and AD10-13-000 - 115 -

requirements of Electric Plant Instruction No.12, Transfers of Property,205 as proposed in 

the NOPR,206 and the provisions of utilities’ formula rate tariffs, as applicable. Utilities 

that do not qualify to use the compliance filing process must first receive approval from a 

relevant rate regulator to revise their existing formula rate tariffs to incorporate the new 

energy storage accounts.

d. Depreciation Rates for Energy Storage Assets

Commission Proposal

176. In the NOPR, the Commission proposed that the cost of energy storage assets be 

charged to depreciation expense using the depreciation rates developed for each 

function.207 

Comments

177. Commenters generally support this proposal. For example, Beacon and ESA 

acknowledge support for the proposal.208 EEI recommends that instead of requiring 

depreciation rates to be based on a utility’s existing rate for a particular function, the 

Commission allow utilities to set initial depreciation rates for new energy storage battery 

equipment based on the manufacturer’s estimated useful life, prior to the utilities 

receiving approval of new depreciation rates through a rate proceeding where new 

 

205 18 CFR Part 101 (2012).

206 NOPR, FERC Stats. & Regs. ¶ 32,690 at P 82.

207 Id.

208 Beacon Comments at 19; and ESA Comments at 19.
Docket Nos. RM11-24-000 and AD10-13-000 - 116 -

approved rates are ordered for these accounts.209 EEI explains that the current life of 

storage batteries is expected to be approximately 10 to 15 years and it contends that this 

expected life can be substantially less than the life used to calculate the depreciation rate 

for the function the asset may be classified under.

Commission Determination

178. For accounting purposes, utilities are required to use percentage rates of 

depreciation that are based on a method of depreciation that allocates in a systematic and 

rational manner the service value of depreciable property over the service life of the 

property.210 Where composite depreciation rates are used, the rate should be based on the 

weighted average estimated useful lives of depreciable property comprising the 

composite group. Furthermore, estimated service lives of depreciable property must be 

supported by engineering, economic, or other depreciation studies.211 To the extent that 

an energy storage asset, such as a battery, has an estimated useful service life that is 

supported by engineering, economic, or other studies of the manufacturer or utility, the 

depreciation rate derived from such study must result in a systematic and rational 

allocation of the asset’s costs over the estimated service life. Therefore, for accounting 

purposes, utilities may set initial rates for new energy storage assets based on 

 

209 EEI Comments at 32.

210 General Instruction No. 22, Depreciation Accounting, 18 CFR Part 101 (2012).

211 Id.
Docket Nos. RM11-24-000 and AD10-13-000 - 117 -

manufacturer or utility estimated service lives that are supported by engineering, 

economic or other studies. In addition, as we indicated above, utilities should use a 

single depreciation rate for an energy storage asset regardless the number of functions to 

which the costs of the asset are allocated.212

e. Jurisdictional Authority

179. The California PUC warns that the Commission’s authority over the accounting 

and reporting for energy storage assets should not limit or infringe upon States’

jurisdictional authority over the assets as the majority of the assets are likely to be 

financed pursuant to state jurisdictional procurement authority.213 

Commission Determination

180. The accounting and reporting requirements of this rulemaking are not intended to 

limit or infringe upon States’ jurisdictional authority. Pursuant to section 301(a) of the 

Federal Power Act (FPA), the Commission has authority to prescribe a system of 

accounts and rules and regulations that are applicable in principle to all licensees and 

public utilities subject to the Commission’s accounting and reporting requirements.214 

The Commission may determine the accounts in which particular outlays and receipts 

will be entered, charged or credited. The amendments to the accounting and reporting 

 

212 See supra P 128.

213 California PUC Comments at 8. 

214 16 U.S.C. 825(a).
Docket Nos. RM11-24-000 and AD10-13-000 - 118 -

requirements are in accordance with the authority bestowed upon the Commission under 

the FPA and as such do not preempt or affect any jurisdiction a State commission or other 

State authority may have under applicable State and Federal law or limit the authority of 

a State commission in accordance with State and Federal law.

f. Implementation Date

181. EEI requests clarification of the implementation date of the proposed accounting 

and reporting requirements. EEI states that it believes assets and related amounts 

recorded in other accounts under the existing accounting requirements should be 

reclassified to the new energy storage accounts provided the asset meets the definition of 

an energy storage asset.215 However, EEI argues that it would not be beneficial or cost 

effective to require utilities to retroactively amend prior year reports to implement the 

requirements. Therefore, EEI recommends that the accounting and reporting 

requirements be effective prospectively only.

Commission Determination

182. While we agree with EEI that it may not be cost effective to require utilities with 

energy storage assets to retroactively amend prior year reports to implement the 

accounting and reporting requirements of this Final Rule; we disagree with EEI’s 

contention that it would not be beneficial to interested parties desiring more transparent 

reporting of the costs associated with energy storage operations. In these instances, the 

 

215 EEI Comments at 28-29.
Docket Nos. RM11-24-000 and AD10-13-000 - 119 -

Commission must weigh the perceived cost of implementing a requirement against the 

expected benefits of implementation. Although requiring utilities with energy storage 

assets to retroactively implement the requirements would provide a more transparent 

historical record of these utilities energy storage operations, this information would not 

be necessary to provide oversight of these utilities energy storage operations going 

forward. Moreover, it is not clear that the benefits of retroactive implementation are 

sufficient to justify the cost. Consequently, we will not require utilities to retroactively 

implement the accounting and reporting requirements. 

183. Utilities subject to the Commission’s accounting and reporting requirements must 

implement the requirements as of January 1, 2013. Utilities are not required to adjust 

prior year, comparative information reported in 2013 Form Nos. 1 and 1-F that must be 

filed by April 18, 2014, nor are they required to adjust prior year, comparative 

information reported in 2013 Form No. 3-Q reports. However, a footnote disclosure must 

be provided describing any amounts transferred from an existing account to a new energy 

storage account. 

184. Due to outdated software, discussed in more detail below, the adopted new and 

revised schedules of Form Nos. 1, 1-F and 3-Q will not be available for use as of the 

effective date of this Final Rule. Consequently, utilities with energy storage assets and 

those that acquire the assets at a later date must continue or begin, as appropriate, using 

the existing form schedules to report energy storage assets pending availability of the 

new and revised schedules. Furthermore, we direct the Chief Accountant to issue interim 

accounting and reporting guidance for utilities to report to the Commission the costs of 
Docket Nos. RM11-24-000 and AD10-13-000 - 120 -

energy storage operations contemplated in this Final Rule until the new and revised 

schedules are available. 

185. Regarding the reporting software issues, the Commission’s forms software 

applications are built with Visual FoxPro development tools and must be installed on a 

Windows-based computer. Microsoft, the Visual FoxPro vendor, announced in 2007 that 

it would no longer sell or issue new versions of Visual FoxPro and would provide support 

for it only through 2015. Also, over time, the Commission has found that it is difficult to 

update tables in the software to accommodate revisions to existing schedules and add 

new schedules to the forms because Visual FoxPro does not allow data tables to exceed 

two gigabytes. These data size limitations will soon restrict the Commission’s ability to 

add data fields in the forms. These limitations make the forms software application 

outmoded, ineffective, and unsustainable. 

186. Pursuant to Sections 141.1, 141.400, and 385.2011 of the Commission’s 

Regulations,216 Form Nos. 1 and 3-Q must be submitted using electronic media.

217

 Due 

to technology changes that will render the current forms filing process outmoded, 

ineffective, and unsustainable, the Commission will discontinue the use of Commissiondistributed software to file forms. Moreover, because of the software limitations, the new 

 

216 18 CFR 141.1, 141.400, and 385.2011 (2012), respectively.

217 Form No. 1-F filers may also submit the reports electronically; however, the 

Commission’s regulations do not explicitly require these filers to submit the reports 

electronically. See 18 CFR 141.2 (2012).
Docket Nos. RM11-24-000 and AD10-13-000 - 121 -

and revised form schedules will not be available to utilities with energy storage assets and 

those that acquire the assets later as of the effective date of this Final Rule. 

Consequently, due to the time lag between implementation of the accounting and 

reporting requirements adopted here and the availability of a filing platform that 

accommodates the Commission’s reporting forms, utilities should submit their 2013 

Form No. 1 and 2014 Form No. 3-Qs using the existing forms filing process until an 

updated filing platform is made available by the Commission. Commission staff will 

issue appropriate notices and hold technical conferences if necessary concerning changes 

to the filing process.

218

 

D. Other Issues

187. Some commenters raised issues beyond the scope of the NOPR. WSPP argues 

that public utility participation in a competitive market for ancillary services is hindered 

by certain OATT requirements applicable to network transmission customers. 

Specifically, WSPP refers to the requirement that network resources be undesignated as 

such, and thus lose their firm network transmission service, when they are committed to 

third-party sales instead of network load obligations. WSPP points to timing mismatches 

between the operational needs of ancillary service use and the undesignation 

 

218 Filers with energy storage assets and operations may be required to amend and 

refile their 2013 Form Nos. 1 and 1-F and 2014 Form No. 3-Q to report energy storage 

operation information in the schedules adopted in this final rule as a result of the 

anticipated new filing platform. However, these filers will not be required to amend and 

refile previously submitted 2013 Form No. 3-Qs.
Docket Nos. RM11-24-000 and AD10-13-000 - 122 -

requirements of the OATT as the main source of this issue. It argues that the 

Commission previously acknowledged these issues in connection with contingency 

reserves under the Southwest Reserve Sharing Group.219 WSPP argues that this 

undesignation requirement hinders robust participation from network transmission 

customers, including the transmission providers themselves, in ancillary service markets.

188. EEI makes similar arguments with respect to the network resource undesignation 

requirements, and asks that the Commission remain receptive to utility-specific requests 

for flexibility.

220

189. Hydro Association and Public Interest Organizations argue that the Commission 

should develop policies that facilitate long-term contracts with energy storage owners. 

Hydro Association asserts that the Commission should solicit further input on policies 

that would allow RTO, ISO, and stand-alone transmission providers to enter into longterm contracts with energy storage owners.

221

 Public Interest Organizations make similar 

arguments.222

190. Shell Energy suggests that the current distinction between Energy Imbalance and 

Generator Imbalance is unnecessary, and that the two services should be combined into a 

single product. Shell Energy cites similar definitions in the EQR Data Dictionary, and 

 

219 WSPP Comments at 19-21.

220 EEI Comments 21-22.

221 Hydro Association Comments at 4-6.

222 Public Interest Organizations Comments at 11.
Docket Nos. RM11-24-000 and AD10-13-000 - 123 -

states that treating the two services as different products provides little benefit, creates 

unnecessary complexity and may result in confusion and regulatory uncertainty.223

191. Shell Energy also urges the Commission to recognize “Balancing Reserves” as a 

separate energy and capacity product used to firm variable energy resources. Shell 

Energy argues that such a product would be differentiated from ancillary services 

because, unlike ancillary services, it would not be limited to addressing contingencies. 

Shell Energy seeks clarification that such a product would not be considered an ancillary 

service, and thus would not be subject to the Avista restrictions. Rather it would be 

subject to a seller’s existing authorization to sell energy and capacity at market-based 

rates.224 EPSA makes similar arguments regarding the need for a new, non-contingencyrelated balancing reserves product.225

 While WSPP’s comments do not specifically seek 

to identify a new product based on whether or not it can be used for issues other than 

contingencies, as do Shell Energy and EPSA, WSPP nevertheless makes certain similar 

arguments in part of its comments. WSPP asserts that sellers may not always wish to sell 

specific ancillary services, but rather may wish to sell “flexible capacity” products 

capable generally of fulfilling multiple OATT schedules. While its comments are not 

 

223 Shell Energy Comments at 3-4.

224 Shell Energy Comments at 5-6.

225 EPSA Comments at 10-11.
Docket Nos. RM11-24-000 and AD10-13-000 - 124 -

entirely clear on this point, WSPP could be interpreted to argue that the Commission 

should recognize flexible capacity as a product different from ancillary services.

226

 

192. AWEA requests that the Commission explore the role that dynamic transfer 

capability, or lack thereof, plays in protecting against exertion of market power. AWEA 

argues that lack of dynamic transfer capability severely constrains competitive ancillary 

service markets in many parts of the country. AWEA suggests that the Commission 

could require transmission providers to analyze, inventory, and market dynamic 

scheduling capability on a non-discriminatory basis.227

193. Powerex argues that there may be certain locations where there is sufficient 

market liquidity such that a seller should be able to make ancillary service sales without 

performing a separate market power analysis. Powerex believes that these locations 

might be defined by some measure of market liquidity, or by a specific minimum number 

of potential sellers, and gives as examples the trading hubs of Mid-Columbia, CaliforniaOregon Border, Palo Verde, Four Corners, and Mead. Powerex does not suggest specific 

liquidity metrics, but does have suggestions regarding the appropriate minimum number 

of potential suppliers. It suggests that third-party sales to a transmission provider could 

be deemed competitive any time there are: (1) at least three potential suppliers, each 

capable of providing 100 percent of the buyer’s needs for the ancillary service in 

 

226 WSPP Comments at 7.

227 AWEA Comments at 3.
Docket Nos. RM11-24-000 and AD10-13-000 - 125 -

question; or (2) at least five potential suppliers, each capable of meeting a significant 

portion (e.g., at least 25 percent) of the buyer’s need for the ancillary service in question.

Commission Determination

194. With respect to WSPP’s request for more flexibility on the requirements for 

network resource undesignation, the Commission declines to consider such changes on a 

generic basis at this time. This undesignation requirement is intended to ensure that 

network transmission customers cannot inappropriately withhold firm transmission 

capacity from potential competitors. While WSPP is correct that the Commission has

permitted limited deviations from this requirement in connection with established reserve 

sharing groups, we are not persuaded that a more general relaxation is justified. WSPP 

indicates in its comments that a public utility is unable to undesignate the network 

resource providing the energy associated with the provision of ancillary services because 

the unit providing the energy may differ from the unit providing the capacity. This 

suggests that the public utility will be using transmission service from a unit that is 

different from the unit for which transmission service has been reserved. Thus, WSPP is 

essentially asking the Commission to permit a public utility transmission provider to 

implicitly use firm point-to-point transmission service without reserving it or paying for 

it. The Commission has previously expressly prohibited this practice and nothing in the 

comments suggests that the Commission’s concerns are no longer valid.228 Further, 

 

228 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 834.
Docket Nos. RM11-24-000 and AD10-13-000 - 126 -

participating in a reserve sharing group differs from making third-party market sales of 

ancillary services. A reserve sharing group essentially expands a public utility 

transmission provider’s native load obligations to serving other load serving entities’ 

native load in the event of a contingency with like protection in return. Permitting a 

public utility transmission provider to deliver energy associated with its reserve sharing 

group obligations without undesignating the resource providing the energy is an 

appropriate recognition of the network service elements of reserve sharing arrangements. 

On the other hand, market sales of ancillary services must be delivered using point-topoint transmission service.

195. With respect to the requests of Hydro Association and Public Interest 

Organizations to facilitate long-term contracting with energy storage owners, we see no 

basis for any additional action at this time. In bilateral markets, assuming that parties are 

able to avoid the Avista restrictions through use of one of the options provided in this 

rule, potential buyers including transmission owners and sellers are free to transact 

through contracts of whatever length they find mutually agreeable. 

196. Shell Energy’s suggestion that Energy Imbalance and Generator Imbalance 

services be combined into a single product is beyond the scope of this rulemaking, and 

Shell Energy’s arguments in support of this idea do not rise to a level concrete enough to 

justify such an expansion at this time.

197. With respect to Shell Energy and EPSA’s comments regarding recognition of noncontingency-related balancing reserves as separate from ancillary services, and WSPP’s 

similar discussion of “flexible capacity,” we clarify that sales of energy and capacity at 
Docket Nos. RM11-24-000 and AD10-13-000 - 127 -

market-based rates are permissible, provided the buyer may not use the purchases to meet 

its OATT obligations to provide Regulation and Frequency Response or Reactive Supply 

and Voltage Control ancillary services.

198. AWEA’s comments regarding dynamic transfer capability raise issues beyond the 

scope of this rulemaking, which have not been fully explored in this proceeding, and 

whose resolution is not necessary to the completion of this rulemaking. Accordingly, the 

Commission will not direct changes with respect to dynamic scheduling or dynamic 

transfer capability at this time.

199. Regarding Powerex’s argument for development of a new market liquidity screen 

for ancillary service market power, we decline to attempt such development at this time. 

The record does not currently support either development of a generic market liquidity 

metric, or the particular minimum participant number thresholds proposed by Powerex. 

We remain open to a more detailed discussion of these ideas in the future if needed, but at 

this time will move forward with the rule changes contained elsewhere in this Final Rule, 

which we hope will reduce the need to develop alternative market power analyses.

III. Summary of Compliance and Implementation

200. With respect to this Final Rule’s reforms to the Avista policy governing sales of 

certain ancillary services to a public utility purchasing the ancillary service to satisfy its 

own OATT requirements to offer ancillary services to its own customers, sellers that have 

a market-based rate tariff on file should revise the provision concerning third-party sales 

of ancillary services, to the extent they have this provision in their tariffs, as follows:
Docket Nos. RM11-24-000 and AD10-13-000 - 128 -

Third-party ancillary services: Seller offers [include all of the following 

that the seller is offering: Regulation and Frequency Response

Service, Reactive Supply and Voltage Control Service, Energy and 

Generator Imbalance Service, Operating Reserve-Spinning Reserves, and 

Operating Reserve-Supplemental Reserves]. Sales will not include the 

following: (1) sales to an RTO or an ISO, i.e., where that entity has no 

ability to self-supply ancillary services but instead depends on third 

parties; and (2) 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 open access transmission tariff requirements to offer 

ancillary services to its own customers. Sales of Operating ReserveSpinning and Operating Reserve-Supplemental will not include sales 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, except where the Commission has granted authorization. Sales 

of Regulation and Frequency Response Service and Reactive Supply and 

Voltage Control Service will not include sales 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, except 

at rates not to exceed the buying public utility transmission provider’s 
Docket Nos. RM11-24-000 and AD10-13-000 - 129 -

OATT rate for the same service or where the Commission has granted 

authorization.

201. While the authorization is effective as of the date specified in this Final Rule, 

sellers should file this tariff revision the next time they make a market-based rate 

filing with the Commission. To the extent sellers do not currently have this provision in 

their tariff but wish to make third-party sales of ancillary services, they should include 

this revised provision in their tariff the next time they make a market-based rate 

filing with the Commission.

202. With regard to sales of Operating Reserves, as discussed above, both sellers that 

have a market-based rate tariff on file and applicants seeking new market-based rate 

authority must satisfactorily make the required showing and receive Commission 

authorization before making sales of Operating Reserve-Spinning and Operating 

Reserve-Supplemental to a public utility that is purchasing Operating Reserve-Spinning 

and Operating Reserve-Supplemental to satisfy its own open access transmission tariff 

requirements to offer ancillary services to its own customers.

203. With respect to the Final Rule’s reforms to provide greater transparency with 

regard to reserve requirements for Regulation and Frequency Response, within 30 days 

from the effective date of this Final Rule, we require each public utility transmission 

provider to revise its OATT Schedule 3 consistent with the revised Schedule 3 in 

accordance with Appendix B to this Final Rule.

204. With respect to Final Rule’s reforms to our accounting and reporting regulations, 

Utilities subject to these requirements must implement the requirements as of January 1, 
Docket Nos. RM11-24-000 and AD10-13-000 - 130 -

2013. Utilities are not required to adjust prior year, comparative information reported in 

2013 Form Nos. 1 and 1-F that must be filed by April 18, 2014, nor are they required to 

adjust prior year, comparative information reported in 2013 Form No. 3-Q reports. 

However, a footnote disclosure must be provided describing any amounts transferred 

from an existing account to a new energy storage account. 

205. Due to outdated software, discussed in more detail in the body of this Final Rule, 

the adopted new and revised schedules of Form Nos. 1, 1-F and 3-Q will not be available 

for use as of the effective date of this Final Rule. Consequently, utilities with energy 

storage assets and those that acquire the assets at a later date must continue or begin, as 

appropriate, using the existing form schedules to report energy storage assets pending 

availability of the new and revised schedules.

IV. Information Collection Statement

206. The following collections of information contained in this Final Rule have been 

submitted to the Office of Management and Budget (OMB) for review under Section 

3507(d) of the Paperwork Reduction Act of 1995.229 OMB’s regulations require approval 

of certain information collection requirements imposed by agency rule.230 Upon approval 

of a collection of information, OMB will assign an OMB control number and an 

expiration date. Respondents subject to the filing requirements of a rule will not be 

 

229 See 44 U.S.C. 3507(d).

230 5 CFR 1320.11 (2012).
Docket Nos. RM11-24-000 and AD10-13-000 - 131 -

penalized for failing to respond to these collections of information if the collections of 

information do not display a valid OMB control number.

Burden Estimate: The additional estimated public reporting burdens and costs for the 

reporting requirements in this Final Rule are as follows. 231

Data 

Collection

Number 

of 

Responde

nts

(a)

Change in 

the Number 

of Hours 

Per Filing 

(averaging 

implementa

tion over 

Yrs. 1-3)232

(b) (hrs.)

Filings Per 

Respondent 

Per Year 

(c)

Change in the 

Total Annual 

Hours for this 

Collection

(averaging 

implementatio

n over Yrs. 1-3)

(aXbXc=d) 

(hrs.)

Estimated 

Annual Cost 

(averaging 

implementatio

n over Yrs. 1-

3) 

(at $120/hr.)

(dX$120/hr.)

($)

Form No. 1

210

7 [3 hrs. 

(one-time 

implementat

ion in Year 

1), plus 6

hrs. 

annually] 1 1,470 176,400

Form No. 

1-F

5

7 [3 hrs. 

(one-time 

implementat 1 35 4,200

 

231 In the NOPR, the Commission proposed changes to FERC-919 (related to the 

’20 percent screen’). The FERC-919 is not affected by the Final Rule. In addition, 

changes to FERC-516, which were not contained in the NOPR, are included in the Final 

Rule.

232 For the Forms 1 and 1-F, the one-time implementation burden in Year 1 is 

estimated to be 3 hours per respondent. However, for the burden and cost estimates, we 

are averaging those additional 3 hours over Years 1-3, giving an average annual one-time 

implementation burden of 1 hour. That 1 hour is in addition to the normal annual filing 

burden of 6 hours each, giving an average annual estimate of 7 hours for Forms 1 and 1-

F, for Years 1-3.
Docket Nos. RM11-24-000 and AD10-13-000 - 132 -

ion in Year 

1), plus 6 

hrs. 

annually]

Form No. 

3-Q 213 1 3 639 76,680

FERC-917 

[includes 

one-time 

filing of 

Pro forma 

openaccess 

transmissio

n tariff 

(OATT) & 

data 

sharing] 233 132

17.33 

averaged 

over Years 

1-3 [4 hrs. 

one-time in 

Yr. 1, plus 

an average

recurring 

burden in 

Years 1-3 of 

16 hrs.] 1

2,288 averaged 

over Years 1-3 

274,560

averaged over 

Years 1-3

FERC-516 no change no change no change no change no change

FERC-717 

(OASIS 

posting 

under 18 

CFR 176 1 1 176 9,889234

 

233 This includes the one-time refiling of OATT Schedule 3 (estimated average of 

4 hours per utility respondent), and if requested, the utility’s sharing data and a narrative 

description with its self-supplying customer(s) (estimated average of 4 customer requests 

per utility respondent per year, taking 4 hours per request). The estimated annual burden 

per utility is

 Year 1: 4 hrs. (for one-time refiling) + (4 requests * 4 hrs.), giving an estimate 

of 20 hrs. per utility

 Years 2 and 3, each: 4 requests * 4 hrs., giving 16 hrs. per utility per year.

When the one-time implementation burden (of 4 hours) is averaged over Years 1-3, the 

annual additional burden per utility is 17.33 hours. 

234 Based on the 2012 data from the Bureau of Labor Statistics at 

http://bls.gov/oes/current/naics2_22.htm, the hourly cost of salary plus benefits would be 

$56.19. 
Docket Nos. RM11-24-000 and AD10-13-000 - 133 -

37.6k)

Total

4,608 (averaged 

over Years 1-3)

$541,729

(averaged over 

Years 1-3)

In paragraph 96, the Commission is requiring that any third-party seller seeking to sell 

ancillary services to a public utility transmission provider through a competitive 

solicitation will need to demonstrate compliance with the competitive solicitation 

requirements of this rule, through a filing under section 205 of the Federal Power Act. 

This requirement for submittal in a section 205 filing would be made under FERC-516 

(OMB Control No. 1902-0096). The filing would be submitted by the seller to the 

Commission prior to commencement of service under the third-party ancillary service 

sales agreement that results from the competitive solicitation. The filing will include 

both the actual sales agreement and a narrative description of how the buyer’s 

competitive solicitation meets the requirements of this Final Rule. Meeting those 

requirements demonstrates the justness and reasonableness of the resulting rate. If the 

seller did not have this option to sell under the competitive solicitation, the seller could 

not use market-based rates and would have to either submit an application for cost-based 

rates under FERC-516 or an application seeking waiver of the Avista restrictions on a 

case-by-case basis.235 The Commission believes that the burden associated with the new 

requirements is far less burden than a full cost-of-service rate filing and approximately 

 

235 See, e.g., Powerex, 125 FERC ¶ 61,179 (2008).
Docket Nos. RM11-24-000 and AD10-13-000 - 134 -

the same burden as the burden associated with an Avista waiver filing. In addition, the 

numbers of respondents and filings are not expected to change significantly. Therefore, 

no changes are proposed to the burden or number of responses for FERC-516.

Title: FERC Form No. 1, “Annual Report of Major Electric Utilities, Licensees, and 

Others;” FERC Form No. 1-F, “Annual Report for Nonmajor Public Utilities and 

Licensees;” FERC Form No. 3-Q, “Quarterly Financial Report of Electric Utilities, 

Licensees and Natural Gas Companies;” FERC-917, “Non-discriminatory Open Access 

Transmission Tariff;” FERC-516, “ Electric Rate Schedules and Tariff Filings,” and 

FERC-717, “Open Access Same-Time Information System and Standards for Business 

Practices & Communication Protocols.”

Action: Proposed revisions to information collections.

OMB Control Nos.: 1902-0021 (FERC Form No. 1); 1902-0029 (FERC Form No.

1-F); 1902-0205 (FERC Form No. 3-Q); 1902-0233 (FERC-917), 1902-0096 (FERC516), and 1902-0173 (FERC-717).

Respondents: Businesses or other for profit and/or not-for-profit institutions.

Frequency of responses: Annually (FERC Form Nos. 1 and 1-F, and FERC-717);

quarterly (FERC Form No. 3-Q); and as needed (FERC-917 and FERC-516).

Necessity of the Information: The final rule amends the Commission’s regulations to 

reflect changes that are occurring in the electric industry due to the availability of new 

energy storage technologies that are being used in the provision of large-scale utility 

operations. These technologies are providing services that were typically provided by 
Docket Nos. RM11-24-000 and AD10-13-000 - 135 -

traditional single-purpose production, transmission and distribution resources. The 

addition of these new plant accounts and new and amended reporting forms are intended 

to enhance transparency and provide detailed information on transactions and events 

affecting public utilities and licensees that file reports with the Commission. The 

accounting regulations currently found in the USofA and related reporting requirements 

capture financial and operational information along traditional primary business functions 

but do not provide sufficient detailed information concerning energy storage operations,

and in particular, the costs incurred by organizations using these resources to 

simultaneously provide multiple utility services with a single asset. The addition of these 

accounts is intended to improve the transparency, completeness and consistency of 

accounting practices for the cost of assets, the expenses incurred in providing services, 

along with revenues collected. Without specific instructions and accounts for recording 

and reporting the above transactions and events, inconsistent and incomplete accounting 

and reporting will result.

Internal Review: The Commission has reviewed the requirements pertaining to the 

USofA and to the reports it prescribes and determined that the proposed amendments are 

necessary because the Commission needs to establish uniform accounting and reporting 

requirements for the costs of utility assets and the expenses incurred for providing 

services as part of its operations.

These requirements conform to the Commission’s need for efficient information 

collection, communication, and management within the energy industry. The 

Commission has assured itself, by means of internal review, that there is specific, 
Docket Nos. RM11-24-000 and AD10-13-000 - 136 -

objective support for the burden estimates associated with the information collection 

requirements.

Interested persons may obtain information on the reporting requirements by contacting 

the following: Federal Energy Regulatory Commission, 888 First Street, NE,

Washington, D.C. 20426 [Attention: Ellen Brown, Office of the Executive Director], email: DataClearance@ferc.gov, Phone (202) 502-8663, fax: (202) 273-0873.

Comments on the collection of information and the associated burden estimates in the 

rule should be sent to the Commission in this docket and may also be sent to the Office of 

Information and Regulatory Affairs, Office of Management and Budget, Washington, 

D.C. 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. 3-Q), and 

1902-0233 (FERC-917), 1902-0096 (FERC-516), and 1902-0173 (FERC-717) and

Docket Number RM11-24.

V. Environmental Analysis

207. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 
Docket Nos. RM11-24-000 and AD10-13-000 - 137 -

on the human environment.236 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact Statement is required for this Final Rule under 

section 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the FPA relating to the 

filing of schedules containing all rates and charges for the transmission or sale subject to 

the Commission’s jurisdiction, plus the classification, practices, contracts, and 

regulations that affect rates, charges, classifications, and services.237

VI. Regulatory Flexibility Act 

208. The Regulatory Flexibility Act of 1980 (RFA)238 generally requires a description 

and analysis of rules that will have significant economic impact on a substantial number 

of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a proposed rule and that minimize any significant 

economic impact on a substantial number of small entities. The Small Business 

Administration’s (SBA) Office of Size Standards develops the numerical definition of a

small business.239 The SBA has established a size standard for electric utilities, stating 

that a firm is small if, including its affiliates, it is primarily engaged in the transmission, 

 

236 Regulations Implementing the National Environmental Policy Act, Order 

No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Regulations Preambles 

1986-1990 ¶ 30,783 (1987).

237 18 CFR 380.4(a)(15) (2012).

238 5 U.S.C. 601-612.

239 13 CFR 121.101 (2011).
Docket Nos. RM11-24-000 and AD10-13-000 - 138 -

generation and/or distribution of electric energy for sale and its total electric output for 

the preceding twelve months did not exceed four million megawatt hours.240 The rule 

applies exclusively to public utilities that own, control, or operate facilities for 

transmitting electric energy in interstate commerce and not electric utilities per se. Based 

on the filers of the 2011 annual FERC Form No. 1 and Form No. 1-F, as well as the 

number of companies that have obtained waivers, we estimate that 44 entities (20 percent 

of the filers) affected by this proposed rule are “small.” For each of the 44 “small” 

entities, the Commission estimates an additional annual burden of only ten hours (seven 

hours for the annual Form 1 or Form 1-F (averaging implementation over years 1-3), plus 

one hour per quarter for the Form 3-Q). The Commission believes this rule will not have 

a significant economic impact on a substantial number of small entities, and therefore no 

regulatory flexibility analysis is required.

VII. Document Availability

209. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov) and in the Commission’s Public Reference Room during normal 

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426.

 

240 13 CFR 121.201, Sector 22, Utilities. 
Docket Nos. RM11-24-000 and AD10-13-000 - 139 -

210. From the Commission’s Home Page on the Internet, this information is available 

on eLibrary. The full text of this document is available on eLibrary in PDF and 

Microsoft Word format for viewing, printing, and/or downloading. To access this 

document in eLibrary, type the docket number, excluding the last three digits of this 

document in the docket number field.

211. User assistance is available for eLibrary and the Commission’s 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. Email the Public Reference Room at 

public.referenceroom@ferc.gov.

Effective Date and Congressional Notification. These regulations are effective [insert 

date 120 days from publication in Federal Register]. The Commission has determined, 

with the concurrence of the Administrator of the Office of Information and Regulatory 

Affairs of OMB, that this rule is not a “major rule” as defined in section 351 of the Small 

Business Regulatory Enforcement Fairness Act of 1996.

List of subjects in 18 CFR Parts 35, 101 and 141

Electric power rates; Electric utilities; Electric power; Uniform System of Accounts

By direction of the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket Nos. RM11-24-000 and AD10-13-000 - 140 -

In consideration of the foregoing, the Commission proposes to amend Parts 35 and 

101, 

Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS

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

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

7352.

2. Amend § 35.37 by revising subsection (c)(1) as follows.

§ 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, generator imbalance, 

operating reserve-spinning, and operating reserve-supplemental services if it passes two 

indicative market power screens: a pivotal supplier analysis based on annual peak 

demand of the relevant market, and a market share analysis applied on a seasonal basis. 

There will be a rebuttable presumption that a seller possesses horizontal market power 

with respect to sales of energy, capacity, energy imbalance, generator imbalance,

operating reserve-spinning, and operating reserve-supplemental services if it fails either 

screen.

* * * * *

3. Amend § 35.38 as follows:

a. Paragraph (a) is revised.
Docket Nos. RM11-24-000 and AD10-13-000 - 141 -

b. Paragraph (b) is revised.

c. New paragraph (c) is added.

§ 35.38 Mitigation.

* * * * *

(a) A Seller that has been found to have market power in generation or ancillary 

services, or that is presumed to have horizontal market power in generation or ancillary 

services by virtue of failing or foregoing the relevant market power screens, as described 

in 35.37(c), may adopt the default mitigation detailed in paragraph (b) of this section for 

sales of energy or capacity or paragraph (c) of this section for sales of ancillary services 

or may propose mitigation tailored to its own particular circumstances to eliminate its 

ability to exercise market power. Mitigation will apply only to the market(s) in which the 

Seller is found, or presumed, to have market power. 

(b) Default mitigation for sales of energy or capacity consists of three distinct 

products:

* * * * *

(c) Default mitigation for sales of ancillary services consist of: (1) a cap based on 

the relevant OATT ancillary service rate of the purchasing transmission operator; or (2) 

the results of a competitive solicitation that meets the Commission’s requirements for 

transparency, definition, evaluation, and competitiveness. 

4. Amend § 37.6 by adding a new paragraph (k) as follows:

§ 37.6 Information to be posted on the OASIS.
Docket Nos. RM11-24-000 and AD10-13-000 - 142 -

* * * * *

(k) Posting of historical area control error data. The Transmission Provider 

must post on OASIS historical one-minute and ten-minute area control error data for the 

most recent calendar year, and update this posting once per year.

PART 101 - UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC

UTILITIES AND LICENSES SUBJECT TO THE PROVISIONS OF THE

FEDERAL POWER ACT

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

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

7352, 7651-7651o.

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

Electric Plant Chart of Accounts

* * * * *

2. PRODUCTION PLANT

* * * * *

D. OTHER PRODUCTION

* * * * *

348 Energy Storage Equipment-Production
Docket Nos. RM11-24-000 and AD10-13-000 - 143 -

* * * * *

7. 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 purchased to energize the equipment are includible on 

the first installation only. The cost of removing, relocating and resetting energy storage 

equipment shall not be charged to this account but to Account 562.1, Operation of Energy

Storage Equipment, and Account, 570.1, Maintenance of Energy Storage Equipment, as 

appropriate. 

C. The records supporting this account shall show, by months, the function(s) each 

energy storage asset supports or performs. 
Docket Nos. RM11-24-000 and AD10-13-000 - 144 -

ITEMS

1. Batteries/Chemical

2. Compressed Air

3. Flywheels

4. Superconducting Magnetic Storage

5. Thermal

8. 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 accordance with Electric Plant Instruction No. 12, Transfers of Property.

B. Labor costs and power purchased to energize the equipment are includible on 
Docket Nos. RM11-24-000 and AD10-13-000 - 145 -

the first installation only. The cost of removing, relocating and resetting energy storage 

equipment shall not be charged to this account but to Account 582.1, Operation of Energy

Storage Equipment, and Account, 592.1, Maintenance of Energy Storage Equipment, as 

appropriate. 

C. The records supporting this account shall show, by months, the function(s) each 

energy storage asset supports or performs. 

ITEMS

1. Batteries/Chemical

2. Compressed Air

3. Flywheels

4. Superconducting Magnetic Storage

5. Thermal

9. In Part 101, Electric Plant Accounts, new primary plant account 348 is added to 

read as follows:

Electric Plant Accounts

* * * * *

348, Energy Storage Equipment-Production

A. This account shall include the cost installed of energy storage equipment used 

to store energy for load managing purposes. Where energy storage equipment can 
Docket Nos. RM11-24-000 and AD10-13-000 - 146 -

perform more than one function or purpose, the cost of the equipment shall be allocated 

among production, transmission, and distribution plant based on the services provided by 

the asset and the allocation of the asset’s cost through rates approved by a relevant 

regulatory agency. Reallocation of the cost of equipment recorded in this account shall 

be in accordance with Electric Plant Instruction No. 12, Transfers of Property.

B. Labor costs and power purchased to energize the equipment are includible on 

the first installation only. The cost of removing, relocating and resetting energy storage 

equipment shall not be charged to this account but to accounts Account 548.1, Operation 

of Energy Storage Equipment, and Account 553.1, Maintenance of Energy Storage 

Equipment., as appropriate. 

C. The records supporting this account shall show, by months, the function(s) each 

energy storage asset supports or performs. 

ITEMS

1. Batteries/Chemical

2. Compressed Air 

3. Flywheels

4. Superconducting Magnetic Storage

5. Thermal

NOTE: The cost of pumped storage hydroelectric plant shall be charged to hydraulic 

production plant. These are examples of items includible in this account. This list is not 
Docket Nos. RM11-24-000 and AD10-13-000 - 147 -

exhaustive.

10. In Part 101, Operation and Maintenance Expense Chart of Accounts, 

Accounts 548.1, 553.1, 555.1, 562.1, 570.1, 584.1, and 592.2 are added to the list:

Operation and Maintenance Expense Chart of Accounts

* * * * *

1. POWER PRODUCTION EXPENSES

* * * * *

D. OTHER POWER GENERATION 

* * * * *

Operation

* * * * *

548.1 Operation of Energy Storage Equipment

* * * * *

Maintenance

553.1 Maintenance of Energy Storage Equipment

* * * * *

E. OTHER POWER SUPPLY EXPENSES

* * * * *
Docket Nos. RM11-24-000 and AD10-13-000 - 148 -

555.1 Power Purchased for Storage Operations

* * * * *

2. TRANSMISSION EXPENSES

* * * * *

Operation

* * * * *

562.1 Operation of Energy Storage Equipment

* * * * *

Maintenance

* * * * *

570.1 Maintenance of Energy Storage Equipment

* * * * *

4. DISTRIBUTION EXPENSES

* * * * *

Operation

* * * * *

584.1 Operation of Energy Storage Equipment

* * * * *
Docket Nos. RM11-24-000 and AD10-13-000 - 149 -

Maintenance

* * * * *

592.2 Maintenance of Energy Storage Equipment

11. 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.

12. In Part 101, Operation and Maintenance Expense Accounts, new maintenance 

expense account 553.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

553.1 Maintenance of Energy Storage Equipment

This account shall include the cost of labor, materials used and expenses incurred 

in the maintenance of energy storage equipment includible in Account 348, Energy 
Docket Nos. RM11-24-000 and AD10-13-000 - 150 -

Storage Equipment-Production, which are not specifically provided for or are readily 

assignable to other production maintenance expense accounts.

13. 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 
Docket Nos. RM11-24-000 and AD10-13-000 - 151 -

exchange or power pooling contract.

14. 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.

15. 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.
Docket Nos. RM11-24-000 and AD10-13-000 - 152 -

16. In Part 101, Operation and Maintenance Expense Accounts, new operation 

expense account 584.1 is added to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

584.1 Operation of Energy Storage Equipment

This account shall include the cost of labor, materials used and expenses incurred 

in the operation of energy storage equipment includible in Account 363, Energy Storage 

Equipment-Distribution, which are not specifically provided for or are readily assignable 

to other distribution operation expense accounts.

17. 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.

18. In Part 101, Operation and Maintenance Expense Accounts, maintenance 

expense account 592 is amended to read as follows:
Docket Nos. RM11-24-000 and AD10-13-000 - 153 -

Operation and Maintenance Expense Accounts

* * * * *

592 Maintenance of Station Equipment (Major only)

This account shall include the cost of labor, materials used and expenses incurred 

in maintenance of plant, the book cost of which is includible in account 362, Station 

Equipment. (See operating expense instruction 2.) 

19. In Part 101, Operation and Maintenance Expense Accounts, maintenance 

expense account 592.1 is amended to read as follows:

Operation and Maintenance Expense Accounts

* * * * *

592.1 Maintenance of Structures and Equipment (Nonmajor only)

This account shall include the cost of labor, materials used and expenses incurred 

in maintenance of structures, the book cost of which is includible in account 361, 

Structures and Improvements, and account 362, Station Equipment. (See operating 

expense instruction 2.)
Docket Nos. RM11-24-000 and AD10-13-000 - 154 -

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 Proposed Rulemaking on Third-Party Provision 

of Ancillary Services; Accounting and Financial Reporting for New Electric Storage 

Technologies – Docket No. RM11-24-000, June 2012

Short Name or Acronym Commenter

APPA American Public Power Association 

AWEA American Wind Energy Association

Beacon Beacon Power Corporation

California PUC California Public Utilities Commission

California Storage Alliance California Energy Storage Alliance 

EEI Edison Electric Institute

Electricity Consumers Electricity Consumers Resource Council

ENBALA ENBALA Power Networks

EPSA Electric Power Supply Association 

ESA Electricity Storage Association 

FTC Staff Staff of the Federal Trade Commission

Hydro Association National Hydropower Association 

Iberdrola Iberdrola Renewables, LLC

Indicated Suppliers Calpine Corporation, Dynegy Inc., 

Exelon Corporation, GenOn Energy, 

Inc., and Tenaska Energy, Inc.

Midwest ISO Midwest Independent Transmission 

System Operator Inc.

Morgan Stanley Morgan Stanley Capital Group Inc.

NAATBatt National Alliance for Advanced 
Docket Nos. RM11-24-000 and AD10-13-000 - 155 -

Technology Batteries

New York ISO New York Independent System 

Operator, Inc.

NU Companies Northeast Utilities Service Company on 

behalf of Connecticut Light and Power 

Company, Western Massachusetts 

Electric Company, Public Service 

Company of New Hampshire, and 

NSTAR Electric Company

Powerex Powerex Corporation

Public Interest Organizations Center for Rural Affairs, Clean 

Wisconsin, Climate + Energy Project, 

Conservation Law Foundation, 

Environment Northeast, Fresh Energy, 

Land Trust Alliance, Natural Resources 

Defense Council, Pace Energy and 

Climate Center, Project for Sustainable 

FERC Energy Policy, Sierra Club and 

Union of Concerned Scientists 

Public Power Council Public Power Council

SDG&E San Diego Gas & Electric Company 

Shell Energy Shell Energy North America (US), L.P.

Solar Energy Association Solar Energy Industries Association

Southern California Edison Southern California Edison Company

TAPS Transmission Access Policy Study 

Group and Transmission Dependent 

Utility Systems 

Western Group Arizona Public Service, Avista 

Corporation, Bonneville Power 

Administration, Idaho Power Company, 

PacifiCorp, Portland General Electric, 

Xcel Energy Services, Puget Sound 
Docket Nos. RM11-24-000 and AD10-13-000 - 156 -

Energy, Inc., Seattle City Light, and 

Takoma Power

WSPP WSPP, Inc.
Docket Nos. RM11-24-000 and AD10-13-000 - 157 -

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

Appendix B: Pro Forma Open Access Transmission Tariff

The Commission amends Schedule 3, Regulation and Frequency Response Service of the 

pro forma OATT:

SCHEDULE 3

Regulation and Frequency Response Service

Regulation and Frequency Response Service is necessary to provide for the 

continuous balancing of resources (generation and interchange) with load and for 

maintaining scheduled Interconnection frequency at sixty cycles per second (60 Hz). 

Regulation and Frequency Response Service is accomplished by committing on-line 

generation whose output is raised or lowered (predominantly through the use of 

automatic generating control equipment) and by other non-generation resources capable 

of providing this service as necessary to follow the moment-by-moment changes in load. 

The obligation to maintain this balance between resources and load lies with the 

Transmission Provider (or the Control Area operator that performs this function for the 

Transmission Provider). The Transmission Provider must offer this service when the 

transmission service is used to serve load within its Control Area. The Transmission 

Customer must either purchase this service from the Transmission Provider or make 

alternative comparable arrangements to satisfy its Regulation and Frequency Response 

Service obligation. The Transmission Provider will take into account the speed and 

accuracy of regulation resources in its determination of Regulation and Frequency 

Response reserve requirements, including as it reviews whether a self-supplying 
Docket Nos. RM11-24-000 and AD10-13-000 - 158 -

Transmission Customer has made alternative comparable arrangements. Upon request by 

the self-supplying Transmission Customer, the Transmission Provider will share with the 

Transmission Customer its reasoning and any related data used to make the determination 

of whether the Transmission Customer has made alternative comparable arrangements. 

The amount of and charges for Regulation and Frequency Response Service are set forth 

below. To the extent the Control Area operator performs this service for the 

Transmission Provider, charges to the Transmission Customer are to reflect only a passthrough of the costs charged to the Transmission Provider by that Control Area operator.
Docket Nos. RM11-24-000 and AD10-13-000 - 159 -

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

Appendix C – New and Amended Form 1/1F/3Q Pages.

Name of Respondent This Report is: 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 and 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 - 160 -

Name of Respondent This Report is:

Resubmission

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 - 161 -

Name of Respondent This Report is: Date of Report 

(Mo, Da, Yr)

 / /

Year/Period of Report

End of Year/Qtr

LIST OF SCHEDULES (Electric Utility) (Continued)

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:

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 - 162 -

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 - 163 -

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) (Continued)

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
Docket Nos. RM11-24-000 and AD10-13-000 - 164 -

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) (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
Docket Nos. RM11-24-000 and AD10-13-000 - 165 -

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) (Continued)

Retirements

(d)

Adjustments

 (e)

Transfers

 (f)

Balance at End of Year

(g)

Line

No.

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
Docket Nos. RM11-24-000 and AD10-13-000 - 166 -

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)

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 - 167 -

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 - 168 -

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 (583) Overhead Line Expenses

142 (584) Underground Line Expenses

143 (584.1) Operation of Energy Storage Equipment

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 (592.1) Maintenance of Structures and Equipment

155 (592.2) Maintenance of Energy Storage Equipment

156 (593) Maintenance of Overhead Lines

157 (594) Maintenance of Underground Lines

158 (595) Maintenance of Line Transformers

159 (596) Maintenance of Street Lighting and Signal Systems

160 (597) Maintenance of Meters

161 (598) Maintenance of Miscellaneous Distribution Plant

162 TOTAL Maintenance (Enter Total of lines 151 thru 161)

163 TOTAL Distribution Expenses (Enter Total of lines 149 and 162)

FERC FORM NO. 1 (REV. 12-12) Page 322
Docket Nos. RM11-24-000 and AD10-13-000 - 169 -

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) 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 - 170 -

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 Power Purchased for Storage Operations (555.1)

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 - 171 -

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(Continued)

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 - 172 -

Name of Respondent This Report Is: 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 - 173 -

Name of Respondent This Report Is: 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 - 174 -

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.

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 1/1-F/3-Q (REV 12-12) Page 397
Docket Nos. RM11-24-000 and AD10-13-000 - 175 -

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 22 DISPOSITION OF ENERGY

2 Generation (Excluding Station Use) 23 Sales to Ultimate Consumers 

(Including Interdepartmental Sales)

3 Steam 24 Requirements Sales for Resale (See 

Instruction 4, Page 311)

4 Nuclear 25 Non-Requirements Sales for Resale 

(See Instruction 4, Page 311)

5 Hydro-Conventional 26 Energy Furnished Without Charge

6 Hydro=Pumped Storage 27 Energy Used by Company (Electric 

Department Only, Excluding Station 

Use) 

7 Other 28 Total Energy Losses

8 Less Energy for Pumping 29 Total Energy Stored

9 Net Generation (Enter Total of Lines 3 through 8) 30 TOTAL (Enter Total of Lines 23 

Through 29) MUST EQUAL LINE 21 

UNDER SOURCES

10 Purchases (other than for Energy Storage)

11 Purchases for Energy Storage

12 Power Exchanges

13 Received

14 Delivered

15 Net Exchanges (Line 12 minus Line 13)

16 Transmission for Others (Wheeling)

17 Received

18 Delivered

19 Net Transmission for Others (Line 16 minus line 

17)

20 Net Transmission for Others (Losses)

21 TOTAL (Enter Total of Lines 9, 10, 11, 15, 19 and 

20)

FERC FORM NO. 1 (REV. 12-12) Page 401a
Docket Nos. RM11-24-000 and AD10-13-000 - 176 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants)

1. Large plants and pumped storage plants of 10,000 KW or more of installed capacity (name plate ratings)

2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in

a footnote. Give project number.

3. If net peak demand for 60 minutes is not available, give that which is available, specifying period.

4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each plant.

5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production 

Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply 

Expenses."

Line 

No.

Item 

(a)

FERC Licensed Project No.

Plant Name:

(b)

1 Type of Plant Construction (Conventional or Outdoor)

2 Year Originally Constructed

3 Year Last Unit was Installed

4 Total installed cap (Gen name plate Rating in MW)

5 Net Peak Demaind on Plant-Megawatts (60 minutes)

6 Plant Hours Connect to Load While Generating

7 Net Plant Capability (in megawatts)

8 Average Number of Employees

9 Generation, Exclusive of Plant Use – KWh

10 Energy Used for Pumping

11 Net Output for Load (line 9 - line 10) – KWh

12 Cost of Plant

13 Land and Land Rights

14 Structures and Improvements

15 Reservoirs, Dams, and Waterways

16 Water Wheels, Turbines, and Generators

17 Accessory Electric Equipment

18 Miscellaneous Power Plant Equipment

19 Roads, Railroads, and Bridges

20 Asset Retirement Costs

21 Total cost (total 13 thru 20)

22 Cost per KW of installed cap (line 21 / line 4)

23 Production Expenses

24 Operation Supervision and Engineering

25 Water for Power

26 Pumped Storage Expenses

27 Electric Expenses

28 Misc Pumped Storage Power Generation Expenses

29 Rents

30 Maintenance Supervision and Engineering

31 Maintenance of Structures

32 Maintenance of Reservoirs, Dams, and Waterways

33 Maintenance of Electric Plant

34 Maintenance of Misc. Pumped Storage Plant

35 Production Exp Before Pumping Exp (line 24 thru line 34)

36 Pumping Expenses

37 Total Production Exp (total line 35 and line 36)

38 Expenses per KWh of Generation (line 37/ line 9)

39 Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))

FERC FORM NO. 1/1-F (REV. 12-12) Page 408
Docket Nos. RM11-24-000 and AD10-13-000 - 177 -

Name of Respondent This Report is: 

(1) □ An Original

(2) □ A Resubmission

Date of Report

(Mo., Da., Yr.)

Year/Period of Report

End of 

PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued)

6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.

7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 

37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy 

from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per 

net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent 

of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.

FERC Licensed Project No.

Plant Name:

(c)

FERC Licensed Project No.

Plant Name:

(d)

FERC Licensed Project No.

Plant Name:

(e)

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

FERC FORM NO. 1/1-F (REV. 12-12) Page 408
Docket Nos. RM11-24-000 and AD10-13-000 - 178 -

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. 

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 (NEW 12-12) Page 414
Docket Nos. RM11-24-000 and AD10-13-000 - 179 -

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 

Energy Storage 

Operations

(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 (NEW 12-12) Page 415
Docket Nos. RM11-24-000 and AD10-13-000 - 180 -

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

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30 Total

 FERC FORM NO. 1/1-F (NEW 12-12) Page 416
Docket Nos. RM11-24-000 and AD10-13-000 - 181 -

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 (NEW 12-12) Page 419
Docket Nos. RM11-24-000 and AD10-13-000 - 182 -

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 (NEW 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)(Continued)