153 FERC ¶ 61,065

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM14-14-000; Order No. 816]

Refinements to Policies and Procedures for Market-Based Rates for 

Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities

(Issued October 16, 2015)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule

SUMMARY: 

EFFECTIVE DATE: This rule will become effective [Insert_Date 90 days after 

publication in the FEDERAL REGISTER].

FOR FURTHER INFORMATION CONTACT: 

Greg Basheda (Technical Information)

Office of Energy Market Regulation 

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6479

Carol Johnson (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8521

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Refinements to Policies and Procedures for Market-Based 

Rates for Wholesale Sales of Electric Energy, Capacity 

and Ancillary Services by Public Utilities

 Docket No. RM14-14-000

ORDER NO. 816

FINAL RULE

TABLE OF CONTENTS

Paragraph Numbers

I. Introduction ................................................................................................................. 1

II. Background.................................................................................................................. 4

III. Overview of Final Rule ......................................................................................... 12

IV. Discussion.............................................................................................................. 24

A. Horizontal Market Power ...................................................................................... 24

1. Sellers in RTOs/ISOs ........................................................................................ 24

2. Sellers with Fully Committed Long-Term Generation Capacity ...................... 29

3. Relevant Geographic Market for Certain Sellers in Generation-Only Balancing 

Authority Areas ......................................................................................................... 45

4. Reporting Format for the Indicative Screens and SIL Submittals 1 and 2........ 72

5. Competing Imports............................................................................................ 84

6. Capacity Ratings................................................................................................ 87

7. Reporting of Long-Term Firm Purchases........................................................108

8. Clarification of Commission Language in Performing SIL Studies ...............146

B. Vertical Market Power—Land Acquisition Reporting .......................................200

1. Commission Proposal......................................................................................200

2. Comments........................................................................................................202

3. Commission Determination.............................................................................207

C. Notices of Change in Status ................................................................................213

1. Geographic Focus............................................................................................213

2. New Affiliation and Behind-the-Meter Generation ........................................241

3. Reporting of Long-Term Firm Purchases........................................................256

D. Asset Appendix....................................................................................................259

1. Changes to the Existing Columns....................................................................260

2. Reporting Power Purchase Agreements..........................................................268

3. Clarifications Regarding the Existing Columns..............................................272

4. Changes Regarding OATT Waiver and Citations in Transmission Asset List295

5. Electronic Format ............................................................................................301

6. Database...........................................................................................................308

E. Category 1 and Category 2 Sellers......................................................................314
Docket No. RM14-14-000 ii

1. Commission Proposal......................................................................................314

2. Comments........................................................................................................319

3. Commission Determination.............................................................................320

F. Corporate Families ..............................................................................................323

1. Corporate Organizational Charts.....................................................................323

2. Single Corporate Tariff....................................................................................336

G. Part 101 and 141 Waivers....................................................................................339

1. Commission Proposal......................................................................................339

2. Comments........................................................................................................342

3. Commission Determination.............................................................................345

H. Miscellaneous Issues ...........................................................................................351

1. Regional Reporting Schedule ..........................................................................351

2. Affirmative Statement .....................................................................................354

3. Comments of Barrick ......................................................................................357

V. Section-by-Section Analysis of Regulations...........................................................360

VI. Information Collection Statement .......................................................................370

VII. Environmental Analysis ......................................................................................380

VIII. Regulatory Flexibility Act...................................................................................381

IX. Document Availability ........................................................................................384

X. Effective Date and Congressional Notification.......................................................387

Appendix A: Standard Screen Format

Appendix B: Corporate Entities and Assets sample appendix

Appendix C: Regional Reporting Schedule

Appendix D: Generalized Map of Geographic Regions

Appendix E: Summary Tables for SIL Calculation 

Appendix F: List of Commenters and Acronyms
153 FERC ¶ 61,065

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Norman C. Bay, Chairman;

 Philip D. Moeller, Cheryl A. LaFleur,

Tony Clark, and Colette D. Honorable.

Refinements to Policies and Procedures for Market-Based 

Rates for Wholesale Sales of Electric Energy, Capacity 

and Ancillary Services by Public Utilities

Docket No. RM14-14-000

ORDER NO. 816

FINAL RULE

(Issued October 16, 2015)

I. Introduction

1. On June 19, 2014, the Commission issued a Notice of Proposed Rulemaking 

(NOPR), pursuant to sections 205 and 206 of the Federal Power Act (FPA),1in which the 

Commission proposed to revise its current standards for market-based rates for sales of 

electric energy, capacity, and ancillary services.2 The Commission proposed to modify 

and streamline certain aspects of the Commission’s filing requirements to reduce the 

administrative burden on market-based rate sellers3and the Commission. 

 

1

16 U.S.C. 824d, 824e.

2

Refinements to Policies and Procedures for Market-Based Rates for Wholesale 

Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, FERC 

Stats. & Regs. ¶ 32,702 (2014) (NOPR).

3

The term “seller” as used in this Final Rule includes sellers that have already 

been granted market-based rate authority as well as applicants for market-based rate 

authority, unless otherwise noted.
Docket No. RM14-14-000 2

2. This Final Rule represents another step in the Commission’s efforts to modify, 

clarify and streamline certain aspects of its market-based rate program. Some aspects of 

this Final Rule eliminate or refine existing filing requirements, while other aspects of the 

Final Rule require submission of additional information from market-based rate sellers. 

For example, this Final Rule redefines the default relevant geographic market for an 

independent power producer (IPP) with generation capacity located in a generation-only 

balancing authority and requires sellers to report all long-term firm purchases that have 

an associated long-term firm transmission reservation in their indicative screens and asset 

appendices. The Final Rule provides clarification on issues including capacity ratings 

and preparation of simultaneous transmission import limit (SIL) studies. Streamlining is 

accomplished through, for example, elimination of the land acquisition reporting 

requirement, reduction in the number of notice of change in status filings due to 

establishment of a 100 megawatt (MW) threshold for reporting new affiliations, and 

clarification that sellers need not report behind-the-meter generation in the indicative 

screens and asset appendices. The specific components of this rule, in conjunction with 

other regulatory activities, are designed to ensure that the market-based rates charged by 

public utilities are just and reasonable.

3. Pursuant to sections 205 and 206 of the FPA, the Commission is amending its 

regulations to revise Subpart H to Part 35 of Title 18 of the Code of Federal Regulations 

(CFR), which governs market-based rate authorizations for wholesale sales of electric 

energy, capacity, and ancillary services by public utilities. 
Docket No. RM14-14-000 3

II. Background

4. In 1988, the Commission began considering proposals for market-based pricing of 

wholesale power sales. The Commission acted on market-based rate proposals filed by 

various wholesale suppliers on a case-by-case basis. Over the years, the Commission 

developed a four-prong analysis to assess whether a seller should be granted marketbased rate authority: (1) whether the seller and its affiliates lack, or have adequately 

mitigated, market power in generation; (2) whether the seller and its affiliates lack, or 

have adequately mitigated, market power in transmission; (3) whether the seller or its 

affiliates can erect other barriers to entry; and (4) whether there is evidence involving the 

seller or its affiliates that relates to affiliate abuse or reciprocal dealing.

5. In 2006, the Commission issued a notice of proposed rulemaking, which led to the 

issuance in 2007 of Order No. 697, which clarified and codified the Commission’s 

market-based rate policy and generally retained the four prong analyses.

4

 As to the first 

prong, the Commission adopted two indicative screens for assessing horizontal market 

power: the pivotal supplier screen and the wholesale market share screen (with a 20 

percent threshold). Each of these uses a “snapshot in time” approach based on historical 

 

4 Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and 

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

clarified, 121 FERC ¶ 61,260 (2007) (Clarifying Order), 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. Mont. Consumer Counsel v. FERC, 659 F.3d 910 

(9th Cir. 2011), cert. denied, 133 S. Ct. 26 (2012).
Docket No. RM14-14-000 4

data5and serves as a cross check on the other to determine whether sellers may have 

horizontal market power and should be further examined.6 The Commission stated that 

passage of both indicative screens establishes a rebuttable presumption that the seller 

does not possess horizontal market power. Sellers that fail either indicative screen are 

rebuttably presumed to have market power and are given the opportunity to present 

evidence such as a delivered price test (DPT) analysis or historical sales and transmission 

data to demonstrate that, despite a screen failure, they do not have market power.7 The 

Commission specified that in traditional markets (outside regional transmission 

organization/independent system operator (RTO/ISO) markets), the default relevant 

geographic market for purposes of the indicative screens is first, the balancing authority 

area(s) where the seller is physically located, and second, the markets directly 

interconnected to the seller’s balancing authority area (first-tier balancing authority 

areas).8 Generally, sellers that are located in and are members of the RTO/ISO may 

 

5 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 17.

6

Id. PP 62, 75.

7

Id. P 13; 18 CFR 35.37(c)(3). 

8

The Commission also noted that “[w]here a generator is interconnecting to a 

non-affiliate owned or controlled transmission system, there is only one relevant market 

(i.e., the balancing authority area in which the generator is located).” Order No. 697, 

FERC Stats. & Regs. ¶ 31,252 at P 232 n.217.
Docket No. RM14-14-000 5

consider the geographic region under the control of the RTO/ISO as the default relevant 

geographic market for purposes of the indicative screens.9

6. With respect to the vertical market power analysis, in cases where a public utility 

or any of its affiliates owns, operates, or controls transmission facilities, the Commission 

requires that there be a Commission-approved Open Access Transmission Tariff (OATT) 

on file, or that the seller or its applicable affiliate has received waiver of the OATT 

requirement, before granting a seller market-based rate authorization.10 The Commission 

also considers a seller’s ability to erect other barriers to entry as part of the vertical 

market power analysis.11 As such, the Commission requires a seller to provide a 

description of its ownership or control of, or affiliation with an entity that owns or 

controls, intrastate natural gas transportation, storage or distribution facilities; sites for 

generation capacity development; and physical coal supply sources and ownership of or 

control over who may access transportation of coal supplies (collectively, inputs to 

electric power production).12 In Order No. 697-C, the Commission revised the change in 

status reporting requirement in section 35.42 of the Commission’s regulations to require a 

 

9 Where the Commission has made a specific finding that there is a submarket 

within an RTO/ISO, that submarket becomes a default relevant geographic market for 

sellers located within the submarket for purposes of the market-based rate analysis. See

Id. PP 15, 231.

10 Id. P 408.

11 Id. P 440.

12 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 176.
Docket No. RM14-14-000 6

market-based rate seller to report the acquisition of control of sites for new generation 

capacity development on a quarterly basis instead of within 30 days of the acquisition.13 

The Commission adopted a rebuttable presumption that the ownership or control of, or 

affiliation with any entity that owns or controls, inputs to electric power production does 

not allow a seller to raise entry barriers but will allow intervenors to demonstrate 

otherwise.14 Finally, as part of the vertical market power analysis, the Commission also 

requires a seller to make an affirmative statement that it has not erected barriers to entry 

into the relevant market and will not erect barriers to entry into the relevant market.15

7. If a seller is granted market-based rate authority, the authorization is conditioned 

on: (1) compliance with affiliate restrictions governing transactions and conduct between 

power sales affiliates where one or more of those affiliates has captive customers;16 (2) a 

requirement to file post-transaction electric quarterly reports (EQR) with the Commission 

containing: (a) a summary of the contractual terms and conditions in every effective 

service agreement for market-based power sales; and (b) transaction information for 

effective short-term (less than one year) and long-term (one year or longer) market-based 

 

13 Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 at P 18; 18 CFR 35.42(d).

14 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 446; 18 CFR 35.37(c).

15 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 447 (clarifying that the 

obligation in this regard applies to both the seller and its affiliates but is limited to the 

geographic market(s) in which the seller is located).

16 18 CFR 35.39.
Docket No. RM14-14-000 7

power sales during the most recent calendar quarter;17 (3) a requirement to file any 

change in status that would reflect a departure from the characteristics the Commission 

relied upon in granting market-based rate authority;18 and (4) a requirement for large 

sellers to file updated market power analyses every three years.19

8. In Order No. 697, the Commission created two categories of sellers.

20

 Category 1 

sellers are wholesale power marketers and wholesale power producers that own or control 

500 MW or less of generation in aggregate per region; that do not own, operate, or 

control transmission facilities other than limited equipment necessary to connect 

individual generation facilities to the transmission grid (or have been granted waiver of 

the requirements of Order No. 88821); that are not affiliated with anyone that owns, 

operates, or controls transmission facilities in the same region as the seller’s generation 

assets; that are not affiliated with a franchised public utility in the same region as the 

 

17 18 CFR 35.10b.

18 18 CFR 35.42.

19 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 3; 18 CFR 35.37(a)(1).

20 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 848.

21 Promoting Wholesale Competition Through Open Access Non-Discriminatory 

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities 

and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036 (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).
Docket No. RM14-14-000 8

seller’s generation assets; and that do not raise other vertical market power issues.22 

Category 1 sellers are not required to file regularly scheduled updated market power 

analyses. Sellers that do not fall into Category 1 are designated as Category 2 sellers and 

are required to file updated market power analyses.23 However, the Commission may 

require an updated market power analysis from any market-based rate seller at any time, 

including those sellers that fall within Category 1.24

9. In Order No. 697, the Commission further stated that through its ongoing 

oversight of market-based rate authorizations and market conditions, the Commission 

may take steps to address seller market power or modify rates. For example, based on its 

review of updated market power analyses, EQR filings, or notices of change in status, the 

Commission may institute a proceeding under section 206 of the FPA to revoke a seller’s 

market-based rate authorization if it determines that the seller may have gained market 

power since its original market-based rate authorization. The Commission also may, 

based on its review of EQR filings or daily market price information, investigate a 

specific utility or anomalous market circumstance to determine whether there has been a 

 

22 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 849 n.1000; 18 CFR 

35.36(a).

23 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 850.

24 Id. P 853.
Docket No. RM14-14-000 9

violation of RTO/ISO market rules or Commission orders or tariffs, or any prohibited 

market manipulation, and take steps to remedy any violations.25

10. After more than six years of experience with the implementation of Order No. 

697, the Commission proposed a number of changes to the market-based rate program 

which, taken as a whole, it believed would simplify and streamline certain aspects of the 

market-based rate program and reduce the burden on industry and the Commission, while 

continuing to ensure that the standards for market-based rate sales of electric energy, 

capacity and ancillary services result in sales that are just and reasonable. The 

Commission also proposed a number of changes to improve transparency in the marketbased rate program, some of which represent increases in information collected from 

market-based rate sellers.

11. The Commission received 23 comments in response to the NOPR. A list of 

commenters is attached as Appendix F.

26

III. Overview of Final Rule

12. In this Final Rule, we adopt in many respects the proposals contained in the NOPR 

with further modifications and clarifications and decline to adopt others. Our findings are 

summarized below.

 

25 Id. P 5.

26 Although the Commission did not request reply comments, several commenters 

nonetheless submitted reply comments. The Commission will reject such reply 

comments.
Docket No. RM14-14-000 10

13. First, with respect to the Commission’s horizontal market power analysis, we are 

not, at this time, adopting the proposal to relieve market-based rate sellers in RTO/ISO 

markets of the obligation to submit indicative screens. However, we are confirming 

clarifications and adopting many of the other proposed modifications to the horizontal 

market power analysis. For example, we clarify that sellers may explain that their 

generation capacity in the relevant geographic market (including first-tier markets) is 

fully committed in lieu of submitting indicative screens as part of their horizontal market 

power analysis. We also clarify that, when the current Commission-accepted SIL values 

into the relevant market are zero for all four seasons and the seller’s and its affiliates’ 

generation capacity in the relevant market is fully committed, the seller does not need to 

submit indicative screens. In addition, we adopt the NOPR proposal regarding reporting 

of long-term firm purchases.

14. We adopt the proposal to define the default relevant geographic market for an IPP 

located in a generation-only balancing authority area as the balancing authority area(s) of 

each transmission provider to which the IPP’s generation-only balancing authority area is 

directly interconnected. We explain that an IPP should study all of its uncommitted 

generation capacity from the generation-only balancing authority area in the balancing 

authority area(s) of each transmission provider to which it is directly connected, and we 

provide examples and clarification of this policy.

15. We amend the indicative screen reporting format and require that the horizontal 

market power indicative screens and SIL Submittals 1 and 2 be filed in workable 

electronic spreadsheets. We find that solar photovoltaic and solar thermal facilities are 
Docket No. RM14-14-000 11

energy limited. However, we determine that, due to their unique characteristics, solar 

photovoltaic facilities, unlike other energy-limited facilities, must use nameplate capacity 

and may not use historical five-year average capacity factors.

16. We adopt the proposal to require a market-based rate seller to report in its 

indicative screens and asset appendix all of its long-term firm purchases of capacity 

and/or energy that have an associated long-term firm transmission reservation regardless

of whether the market-based rate seller has control over the generation capacity supplying 

the purchased power. We also adopt a modified formula for converting energy to 

capacity, and make corresponding changes to the change in status reporting requirements.

17. We confirm most of the clarifications proposed in the NOPR regarding the SIL 

studies and provide some additional clarifications in response to comments.

18. With respect to the Commission’s vertical market power analysis, we adopt the 

proposal to eliminate the requirement that market-based rate sellers file quarterly land 

acquisition reports and provide information on sites for generation capacity development 

in market-based rate applications and triennial updated market power analyses. With 

respect to other change in status proposals, we clarify that the 100 MW threshold does 

not include generation capacity that can be imported from first-tier markets. Similarly, 

we find that applicants and sellers are not limited to nameplate ratings when determining 

the 100 MW threshold. We have reconsidered the proposed clarification that marketbased rate sellers must account for behind-the-meter generation in their indicative screens 

and asset appendices and find that behind-the-meter generation need not be accounted for 
Docket No. RM14-14-000 12

in the indicative screens and asset appendices and will not count towards the 100 MW 

change in status threshold or the 500 MW Category 1 seller threshold. 

19. We also adopt a 100 MW change in status threshold for reporting new affiliations 

to align with the existing 100 MW threshold for reporting net increases in generation 

capacity.

20. We adopt changes to the asset appendix that sellers must submit with most 

market-based rate filings, and will also require that the asset appendix be submitted in an 

electronic format that can be searched, sorted, and otherwise accessed using electronic 

tools. In addition, based on comments received, we will add two additional worksheets 

to the asset appendix, one for end notes and another for long-term firm purchases. We 

provide some additional clarifications on the asset appendix as well.

21. We adopt the NOPR proposal to require a seller filing an initial application for 

market-based rate authority, an updated market power analysis, or a notice of change in 

status reporting new affiliations to include a corporate organizational chart. However, we 

clarify that the organizational chart need only to include the seller’s affiliates as defined 

in section 35.36(a)(9) of the Commission’s regulations rather than all upstream owners,

“energy subsidiaries” and “energy affiliates.”

22. We adopt the NOPR proposal and clarify that granting waiver of 18 CFR Part 101 

under market-based rate authority does not waive the requirements under Part I of the 

FPA for hydropower licensees. In addition, we clarify how hydropower licensees that 

only make sales at market-based rates may satisfy the requirements in Part 101 of the 

Commission’s regulations (Uniform System of Accounts), and confirm that hydropower 
Docket No. RM14-14-000 13

licensees that have Commission-approved cost-based rates are required to comply with 

the full requirements of the Uniform System of Accounts.

23. We also provide clarifications in the Final Rule with regard to simplifying 

assumptions, the criteria for determining seller category status, how to file a single 

corporate tariff, the regional reporting schedule, and the vertical affirmative statement 

obligation. 

IV. Discussion

A. Horizontal Market Power

1. Sellers in RTOs/ISOs

a. Commission Proposal

24. Section 35.37 of the Commission’s regulations requires market-based rate sellers 

to submit market power analyses: (1) when seeking market-based rate authority; 

(2) every three years for Category 2 sellers; and (3) at any other time the Commission 

requests a seller to submit an analysis. A market power analysis must address a seller’s 

potential to exercise horizontal and vertical market power. If an RTO/ISO seller27 fails 

 

27 RTO/ISO sellers are sellers that study an RTO, ISO, and submarkets therein as a 

relevant geographic market. 
Docket No. RM14-14-000 14

the indicative screens for the RTO/ISO, it can seek to obtain or retain market-based rate 

authority by relying on Commission-approved RTO/ISO monitoring and mitigation.28

25. The Commission proposed to not require sellers in RTO/ISO markets to submit 

indicative screens as part of their horizontal market power analyses if they rely on 

Commission-approved monitoring and mitigation to prevent the exercise of market 

power. Under the proposal, RTO/ISO sellers instead would simply state that they are 

relying on such mitigation to address any potential market power they might have, and 

describe their generation and transmission assets and provide an asset appendix with a list 

of generation assets and entities with market-based rate authority (generation list) and a 

list of transmission assets and natural gas intrastate pipelines and gas storage facilities 

(transmission list). Under this proposal, all RTO/ISO sellers seeking market-based rate 

authority in an RTO/ISO market would make an initial filing, consistent with current 

practice, and those sellers required to file updated market power analyses every three 

years (i.e., Category 2 sellers) would continue to make their scheduled filings. The 

Commission noted that it would retain the ability to require an updated market power 

analysis, including indicative screens, from any market-based rate seller at any time.

 

28 In Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 111, the Commission 

stated that “to the extent a seller seeking to obtain or retain market-based rate authority is 

relying on existing Commission-approved [RTO/ISO] market monitoring and mitigation, 

we adopt a rebuttable presumption that the existing mitigation is sufficient to address any 

market power concerns.”
Docket No. RM14-14-000 15

b. Comments

26. Some commenters support the Commission’s proposal to allow market-based rate 

sellers in RTO/ISO markets with Commission-approved monitoring and mitigation to 

not file indicative screens when submitting initial applications requesting market-based 

rate authority and updated market power analyses.29 Some commenters request that the 

Commission clarify aspects of its proposal30 or extend the proposal to additional 

circumstances.31 Some commenters oppose the Commission’s proposal, raising issues 

regarding the Commission’s legal authority to eliminate the indicative screens32 or the 

effectiveness of RTO/ISO monitoring and mitigation.33 For example, Potomac 

Economics agrees with the general principal underlying the Commission’s proposal, but 

states that in some cases, participants selling into RTO markets may be exempt from 

certain market power mitigation measures or the mitigation measures may not be fully 

 

29 American Electric Power Service Corporation (AEP) at 4-5; Electric Power 

Supply Association (EPSA) at 3-4; FirstEnergy Service Company (FirstEnergy) at 4-5; 

Golden Spread Electric Cooperative, Inc. (Golden Spread) at 6; NextEra Energy, Inc. 

(NextEra) at 2; Subsidiaries of NRG Energy, Inc. (NRG Companies) at 8-9. 

30 See, e.g., E.ON Climate & Renewables North America LLC (E.ON) at 3-4; 

Southern California Edison Company (SoCal Edison) at 16; Julie Solomon and Matthew 

Arenchild (Solomon/Arenchild) at 2; Edison Electric Institute (EEI) at 6.

31 See, e.g., FirstEnergy at 10; AEP at 6; EEI at 7.

32 American Antitrust Institute (AAI) at 3-7; American Public Power Association 

and National Rural Electric Cooperative Association (APPA/NRECA) at 6-21; 

Transmission Access Policy Study Group (TAPS) at 1-2, 5-9, 17-18.

33 Potomac Economics at 3-4.
Docket No. RM14-14-000 16

effective and that the Commission’s proposal may allow some participants with 

potential market power to sell at market-based rates without this market power being 

fully addressed.34 APPA/NRECA contend that the proposal is a fundamental departure 

from the market-based rate scheme that the courts have previously upheld.35

c. Commission Determination

27. The Commission received 15 comments on this issue from a wide variety of 

market participants. Indeed, this was one of the most widely commented upon aspects of 

the Commission’s NOPR. The comments included those who fully support the 

Commission’s proposal, those who favor only portions of it, those who seek clarification 

of it and those who oppose it. And among those who oppose it, there are various reasons 

for their opposition, which include legal, economic, and implementation issues. While 

the Commission considers further the issues that were raised in these comments, we are 

not prepared to adopt at this time the proposal in the NOPR and will continue with our 

current practice of requiring that sellers in RTO/ISO markets submit the indicative 

screens when submitting initial applications requesting market-based rate authority and 

updated market power analyses and relying on the Commission-approved market 

monitoring and mitigation. We will transfer the record on this aspect of the NOPR to 

 

34 Potomac Economics at 2.

35 APPA/NRECA at 8-10 (citing Mont. Consumer Counsel v. FERC, 659 F.3d 

910; California ex rel. Lockyer v. FERC, 383 F.3d 1006 (9th Cir. 2004) (Lockyer); 

Blumenthal v. FERC, 552 F.3d 875,882 (D.C. Cir. 2009) (Blumenthal)).
Docket No. RM14-14-000 17

Docket No. AD16-8-000 for possible consideration in the future as the Commission may 

deem appropriate.

28. Because we continue to value the information obtained through the indicative 

screens and are not prepared at this time to adopt the proposal, market-based rate sellers 

in RTO/ISO markets must continue to submit the indicative screens as part of their 

horizontal market power analysis unless the seller and its affiliates do not own or control 

generation capacity or all of their capacity is fully committed. We will continue to allow 

sellers to seek to obtain or retain market-based rate authority by relying on Commissionapproved RTO/ISO monitoring and mitigation in the event that such sellers fail the 

indicative screens for the RTO/ISO markets.36

2. Sellers with Fully Committed Long-Term Generation Capacity

a. Commission Proposal

29. The Commission has found that, if generation is committed to be sold on a longterm firm basis to one or more buyers and cannot be withheld by a seller, it is appropriate 

for a seller to deduct such capacity when performing the indicative screens.37 In the 

NOPR, the Commission clarified that where all generation owned or controlled by a 

seller and its affiliates in the relevant balancing authority areas or markets including firsttier balancing authority areas or markets is fully committed, sellers may satisfy the 

Commission’s market-based rate requirements regarding horizontal market power by 

 

36 See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 11.

37 See id. P 41. 
Docket No. RM14-14-000 18

explaining that their capacity is fully committed in lieu of including indicative screens in 

their filings. The Commission proposed to clarify that, in order to qualify as “fully 

committed,” a seller must commit the generation capacity so that none of it is available to 

the seller or its affiliates for one year or longer.

30. The Commission proposed that sellers claiming that all of their relevant generation

capacity38 is fully committed would have to include the following information: the 

amount of generation capacity that is fully committed, the names of the counterparties, 

the length of the long-term contract, the expiration date of the contract, and a 

representation that the contract is for firm sales for one year or longer. The Commission 

stated that in order to qualify as fully committed, the commitment of the generation 

capacity cannot be limited during that 12-month consecutive period in any way, such as 

limited to certain seasons, market conditions, or any other limiting factor. Furthermore, 

the Commission stated that a seller’s generation would not qualify as fully committed if, 

for example, the seller has generation necessary to serve native load, provider of last 

resort obligations, or a contract that could allow the seller to reclaim, recall, or otherwise 

use the capacity and/or energy or regain control of the generation under certain 

circumstances (such as transmission availability clauses).

 

38 “Relevant” generation capacity refers to seller and affiliated capacity in the 

study area, including the first tier.
Docket No. RM14-14-000 19

31. Additionally, the Commission stated that, consistent with the existing regulations, 

a change in status filing will be required when a long-term firm sales agreement expires if 

it results in a net increase of 100 MW or more.39 

b. Comments

32. Many commenters support the Commission’s proposal.40 For example, EPSA 

agrees with the Commission’s assessment that the study of uncommitted generation in 

indicative screens becomes a purely mathematical task and provides no significant 

additional information when sellers’ fully-committed long-term capacity is deducted 

from the indicative screens.41 NextEra, also agreeing with the Commission’s proposal, 

states that where all generation owned or controlled by sellers and their affiliates is fully 

committed to purchasers not affiliated with the seller, the ability to exercise market power 

is severely limited or non-existent.42 FirstEnergy states that it supports the proposal 

because a seller whose generation capacity is fully committed on a long-term basis lacks 

 

39 The Commission noted that such a change would be a departure from the 

characteristics the Commission relied upon in granting market-based rate authority. See 

18 CFR 35.42(a). 

40 EPSA at 4; Solomon/Arenchild at 2; NextEra at 3; EEI at 8; FirstEnergy at 7; 

NRG Companies at 10.

41 EPSA at 5.

42 NextEra at 3.
Docket No. RM14-14-000 20

the ability to exercise horizontal market power by withholding such capacity from the 

market.43

33. NRG Companies also support the proposal and request that the Commission 

clarify that even if the seller and/or its affiliates have uncommitted capacity in one or 

more first-tier markets, no indicative screens will be required if all of their generation 

capacity in the relevant market is fully committed under long-term contracts and (1) the 

simultaneous import limitation for the relevant market is zero, indicating that no capacity 

can be imported from affiliates in first-tier markets, or (2) neither the seller nor its 

affiliates have firm transmission rights into the relevant market from any first-tier market 

in which its affiliates have uncommitted capacity.44

34. NextEra states that there is no need to provide screens in balancing authority areas

where all generation owned or controlled by sellers and their affiliates is fully committed 

to purchasers not affiliated with the seller and further requests that the Commission not 

require screens if there is uncommitted capacity in any first-tier market when 100 percent 

of the seller’s generation capacity in the relevant market is fully committed.45

35. EPSA requests clarification that the proposed term “fully committed” would also 

apply to circumstances where a seller retains the right to sell capacity to a second buyer, 

but only when the first buyer under the long-term contract waives the right to purchase. 

 

43 FirstEnergy at 7.

44 NRG Companies at 10-11.

45 NextEra at 4.
Docket No. RM14-14-000 21

EPSA explains that if the buyer under a long-term contract has the right to call on the full 

output of the seller’s generation, and the seller may only offer the capacity to a second 

buyer when the first buyer foregoes its purchase right, then that capacity should be 

considered fully committed and thus, excluded from the indicative screens.46

36. Solomon/Arenchild state that the Commission’s proposal that the exemption from 

the submittal of screens depends, in part, on whether the seller has uncommitted capacity 

in first-tier markets is inconsistent with its general approach in defining geographic 

markets and when screens are required. They recommend that the Commission’s 

proposal be amended. In the NOPR, the Commission stated that “where all generation 

owned or controlled by a seller and its affiliates in the relevant balancing authority areas 

or markets including first-tier balancing authority areas or markets is fully committed, 

sellers may explain that their capacity is fully committed in lieu of including indicative 

screens in their filings in order to satisfy the Commission's market-based rate 

requirements regarding horizontal market power.”47 Solomon/Arenchild propose that the 

language “including first-tier balancing authority areas or markets” be excluded.48 

Alternatively, they state that the definition could be modified to only include first-tier 

 

46 EPSA at 5.

47 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 43 (emphasis added).

48 Solomon/Arenchild at 2-3.
Docket No. RM14-14-000 22

supply that has a corresponding long-term firm transmission agreement into the relevant

balancing authority area.

49

37. With regard to the information a seller must provide, NextEra seeks clarification 

on the phrase “firm sales for one year or longer.” NextEra requests that the Commission 

clarify that the term “firm” has the same meaning as in the Commission’s EQR Data 

Dictionary, where it is defined as “a service or product that is not interruptible for 

economic reasons.”50 

38. NextEra does not oppose the Commission’s proposal to require that sellers provide 

the expiration date of the contract in updated market power analyses, but NextEra states 

that it does not agree with requiring this information in initial market-based rate 

applications. NextEra states that, more often than not, at the time a seller files for 

market-based rate authority, the expiration date is unknown.51 EEI does not support 

requiring the expiration date and notes that the expiration date is reported separately in 

EQR filings.52

 

49 Id. at 3.

50 NextEra at 4-5 (citing http://www.ferc.gov/docs-filing/eqr/order770/datadictionary.pdf).

51 Id. at 5.

52 EEI at 8.
Docket No. RM14-14-000 23

c. Commission Determination

39. Consistent with the NOPR, the Commission clarifies here that when all of a 

seller’s generation capacity is sold on a long-term firm basis to one or more buyers, the 

seller has no uncommitted capacity and in such cases will not be required to file the 

indicative screens. Sellers may explain that their generation capacity is fully committed 

in lieu of including indicative screens in their filings in order to satisfy the Commission’s 

market-based rate requirements regarding horizontal market power in instances where all 

generation owned or controlled by a seller and its affiliates in the relevant balancing 

authority areas or markets, including first-tier balancing authority areas or markets, is 

fully committed. We clarify that to qualify as fully committed, a seller must commit the 

capacity to a non-affiliated buyer so that none of it is available to the seller or its affiliates 

for one year or longer. We also adopt the proposal that for those sellers claiming that all 

of their relevant capacity is fully committed they must include the following information: 

the amount of generation capacity that is fully committed, the names of the 

counterparties, the length of the long-term contract, the expiration date of the contract, 

and a representation that the contract is for firm sales for one year or longer. In order to 

qualify as fully committed, the commitment of the generation capacity cannot be limited 

during that 12-month consecutive period in any way, such as limited to certain seasons, 

market conditions, or any other limiting factor. As stated in the NOPR, a seller’s 

generation would not qualify as fully committed if, for example, that generation is needed 

for the seller to meet its native load or provider of last resort obligations, or the power 

sales contract in question could allow the seller to reclaim, recall, or otherwise use the 
Docket No. RM14-14-000 24

generation capacity and/or energy or regain rights to the generation under certain 

circumstances (such as transmission availability clauses). Additionally, a change in 

status filing will be required when a long-term firm sales agreement expires if it results in 

a net increase of 100 MW or more.

40. We do not adopt the suggestions by NRG Companies, NextEra, and 

Solomon/Arenchild regarding capacity in first-tier markets. We will not implement

NRG Companies’ and NextEra’s proposals that the Commission not require sellers to 

submit indicative screens even if they have uncommitted capacity in one or more firsttier markets as long as all of the seller’s capacity in the relevant market is fully 

committed. A seller may fail an indicative screen in a market where it does not have any 

uncommitted capacity due to its imports into the study area.

53

 However, when the 

current Commission-accepted SIL values into the relevant market are zero for all four 

seasons, the seller does not have to consider imports in its market-power studies. 

Therefore, we clarify that if the seller’s capacity in the relevant market is fully 

committed and all the SIL values into the relevant market are zero, the seller does not 

need to submit the indicative screens. 

41. We do not adopt the suggestion from Solomon/Arenchild to only consider firsttier supply that has long-term firm transmission rights into the relevant market. First-tier 

generation capacity without long-term firm transmission rights still can be imported into 

 

53 For example, this can occur when a seller is relatively large and the study area is 

relatively small and relies significantly on imports to meet its load obligations. 
Docket No. RM14-14-000 25

the relevant market as long as the SIL value is not zero; albeit on a non-firm, pro rata

basis.54 The SIL values used in the Commission’s horizontal market power analysis are 

net of long-term firm transmission reservations. While a seller’s pro rata share of the 

SIL value or transmission capacity that may be used to import generation capacity from 

the first-tier ultimately may be small, it should not be ignored. 

42. We also decline to adopt EPSA’s request that we clarify that a seller’s generation 

capacity is fully committed where the seller retains the right to sell capacity to a second 

buyer.55 We are concerned that permitting a more flexible definition of fully committed 

could create the potential for sellers to claim that their contracts meet the standard for 

fully committed even where it is not clear that the capacity’s output is fully committed. 

Moreover, the contract-specific analysis could create inconsistencies in the way data is 

reported. 

 

54 Stated another way, if the SIL value is not zero, and the seller has uncommitted 

generation capacity in a first-tier market, that uncommitted capacity is capable of 

reaching the study area and will affect the market power analysis. However, a seller’s 

first-tier uncommitted capacity has to compete with non-affiliated first-tier uncommitted

capacity to enter the study area, so the Commission allows sellers to allocate to 

themselves a portion of the SIL value based on the percentage of uncommitted generation 

capacity they and their affiliates own in the aggregated first-tier area in relation to the 

total amount of uncommitted generation capacity in this area. See Order No. 697, FERC 

Stats. & Regs. ¶ 31,252 at PP 373-375. 

55 Here we are referring to a situation in which the seller retains rights to sell the 

same generation capacity to a second buyer. We are not referring to a contractual 

arrangement whereby capacity is fully committed but is sold to multiple buyers; e.g., 500 

MW of a 1,000 MW unit is sold to buyer A, while the remaining 500 MW of the unit is 

sold to buyer B, with A and B having exclusive rights to their respective shares of the 

unit. 
Docket No. RM14-14-000 26

43. With regard to NextEra’s request that the Commission clarify that “firm” has the 

same meaning as in the Commission’s EQR Data Dictionary, we clarify here that the 

term “firm” means a “service or product that is not interruptible for economic reasons,” 

as it is defined in the Commission’s EQR Data Dictionary.

44. We believe that NextEra raises a valid point concerning unknown expiration 

dates. Therefore, we clarify here that if a contract expiration date is unknown at the time 

of the market-based rate filing, the seller must follow up with an informational filing, in 

the docket in which the seller was granted market-based rate authorization, to inform the 

Commission of the contract expiration date, within 30 days of the date becoming known. 

In response to EEI’s argument that the expiration date is reported separately in EQR 

filings, we note many contracts reported in EQR filings do not include expiration dates. 

Further, there can be a time gap between when a seller receives market-based authority 

and when it submits its EQR. This time gap may be as large as 120 days, and would not 

meet the need for this information. Therefore, we will require expiration date 

information to show that generation capacity is fully committed.

3. Relevant Geographic Market for Certain Sellers in GenerationOnly Balancing Authority Areas

a. Commission Proposal

45. In the NOPR, the Commission noted that “the horizontal market power analysis 

centers on and examines the balancing authority area where the seller’s generation is 
Docket No. RM14-14-000 27

physically located”56 and that the default relevant geographic market under both 

indicative screens “will be first, the balancing authority area where the seller is 

physically located [the seller’s home balancing authority area] and second, the markets 

directly interconnected to the seller’s balancing authority area (first-tier balancing 

authority area markets).”57 However, the Commission noted that “[w]here a generator is 

interconnecting to a non-affiliate owned or controlled transmission system, there is only 

one relevant market (i.e., the balancing authority area in which the generator is 

located).”58 Similarly, the Commission noted that RTO/ISO sellers are required “to 

consider, as part of the relevant market, only the relevant [RTO/ISO] market and not 

first-tier markets to the [RTO/ISO].”59

46. The Commission noted that Order No. 697 stated that a “balancing authority area 

means the collection of generation, transmission, and loads within the metered 

boundaries of a balancing authority, and the balancing authority maintains load/resource 

balance within this area.” 60 The Commission further noted that, given that generationonly balancing authority areas do not have any load, these balancing authority areas do 

 

56 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 47 (quoting Order No. 697, FERC 

Stats. & Regs. ¶ 31,252 at P 37).

57 Id. (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232).

58 Id. (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217).

59 Id. (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 231 n.215).

60 Id. P 51.
Docket No. RM14-14-000 28

not appear to meet the Commission definition of a default relevant geographic market. 

In light of the unusual and complex circumstances that are associated with defining the 

relevant geographic market of an IPP located in a generation-only balancing authority 

area, and in light of the fact that a generation-only balancing authority area is not a 

market, the Commission proposed in the NOPR that the default relevant geographic 

market(s) for such a seller would be the balancing authority areas of each transmission 

provider to which its generation-only balancing authority area is directly interconnected. 

The Commission proposed that such IPP seller study all of its uncommitted generation 

capacity from the generation-only balancing authority area in the balancing authority 

area(s) of each transmission provider to which it is directly interconnected, since all such

uncommitted capacity could potentially be sold into any of the markets that are directly 

interconnected to the IPP’s generation-only balancing authority area, even if the IPP has 

not sold into that market.

47. In the NOPR, the Commission stated that “[f]or purposes of market power 

analyses for market-based rate authority, we propose to define an IPP as a generation 

resource that has power production as its primary purpose, does not have any native load 

obligation, is not affiliated with any transmission owner located in the first-tier markets 

in which the IPP is competing and does not have an affiliate with a franchised service 

territory. This IPP could also have an OATT waiver on file with the Commission.”61 

 

61 Id. P 49 n.50.
Docket No. RM14-14-000 29

48. To illustrate the NOPR proposal, the Commission explained that if an IPP is 

located in a generation-only balancing authority area that is embedded within a 

transmission provider’s balancing authority area, and that balancing authority area is the 

only balancing authority area that the IPP’s generation-only balancing authority area is 

directly interconnected with, then the IPP would provide indicative screens for that 

transmission provider’s balancing authority area.62 

49. The Commission provided another example for an IPP located in a generationonly balancing authority area in a remote area such as the desert southwest. In that case, 

the IPP would have to provide indicative screens for the balancing authority area(s) of 

the transmission provider(s) to which its generation-only balancing authority area is 

directly interconnected. The IPP would assume that all of its uncommitted capacity 

could compete in each balancing authority area of the transmission provider(s) to which 

its generation-only balancing authority area is directly interconnected, since all such 

uncommitted capacity could potentially be sold in each market to which there is a direct 

interconnection, even if the IPP has not sold into that market in the past. An IPP in this 

situation would not need to study any first-tier markets.63

 

62 The Commission proposed that an IPP in this situation would not need to study 

the transmission provider’s balancing authority first-tier markets, just as would be the 

case if that generator were similarly located in the transmission provider’s balancing 

authority area. 

63 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217.
Docket No. RM14-14-000 30

50. For an IPP in a generation-only balancing authority area directly interconnected to 

a transmission provider at an energy trading hub, the Commission proposed that the IPP 

would provide indicative screens that study itself in the balancing authority area of each 

transmission provider that is directly interconnected at the trading hub. Thus, the 

balancing authority areas that are directly interconnected at the hub would each be 

relevant geographic markets for that IPP, and the IPP would provide indicative screens 

that study the IPP in each of those transmission providers’ balancing authority areas. 

The Commission proposed that the IPP would provide indicative screens that assume 

that all of its uncommitted capacity may compete in each of the balancing authority 

areas that are directly interconnected at that trading hub, since all such uncommitted 

capacity could potentially be sold in each market to which there is a direct 

interconnection, even if the IPP has not sold into that market in the past. The IPP in this

situation would not need to provide indicative screens that study itself in any markets 

that are first-tier to the various balancing authority areas that are directly interconnected 

at the trading hub.

b. Comments

51. Solomon/Arenchild agree in principal with the Commission’s proposal to define 

relevant geographic market(s) for sellers located in generation-only balancing area as the 

balancing authority areas of each transmission provider to which the generation-only 

balancing authority area is directly interconnected. Solomon/Arenchild suggest that the 

Commission confirm that the proposal also applies to quasi-generation-only balancing 

authority areas, such as Ohio Valley Electric Corporation and Alcoa Power Generating, 
Docket No. RM14-14-000 31

Inc.-Yadkin Division. According to Solomon/Arenchild, in these quasi-generation-only 

balancing authority areas, generation was built to serve load in a balancing authority 

area, but there is no longer any material load present in the balancing authority area.64

52. However, Solomon/Arenchild voice concerns with the Commission’s proposal to 

have an IPP provide screens that study the IPP in the balancing authority area of each 

transmission provider that is directly interconnected at the trading hub. Citing the 

example in the NOPR regarding IPPs interconnected to the Hassayampa switchyard, 

Solomon/Arenchild state that, as proposed, the solution is overly burdensome and likely 

to have unintended consequences.65 They explain that the Commission’s proposal, as 

they understand it, would require New Harquahala Generating Company, LLC 

(Harquahala) and Arlington Valley, LLC (Arlington Valley) to each perform indicative 

screens for all Arizona Nuclear Power Project switchyard participants. They state that 

this would be at least six balancing authority areas and perhaps more, resulting in a 

“significant increase in the scope of the analysis and the burden.”66

 

64 Solomon/Arenchild at 15.

65 The Commission explained in the NOPR that if an IPP in a generation-only 

balancing authority area in the Arizona desert is directly interconnected to a transmission 

provider at the Palo Verde trading hub at the Palo Verde and Hassayampa switchyards, 

then it would provide screens that study all of its uncommitted capacity in each balancing 

authority area that is directly interconnected at the switchyard. NOPR, FERC Stats. & 

Regs. ¶ 32,702 at P 56.

66 Solomon/Arenchild at 15-17 (citing NOPR, FERC Stats. & Regs. ¶ 32,702 at 

P 56).
Docket No. RM14-14-000 32

53. Solomon/Arenchild also argue that the proposal does not clarify many of the steps 

that must be considered. They state that a seller has to determine if each of the analyses 

require a presumption that 100 percent of the output of each of the relevant merchant 

generators can be “imported” into each of the six or more balancing authority areas. 

They further state that the SIL studies done by the transmission owners in the region 

would have to be aligned with the analyses and they question whether that means that 

each of the balancing authority areas would be required to conduct two SIL studies –

one that assumes each of the potentially relevant generators reside “within” their 

balancing authority areas and one that does not. Solomon/Arenchild also question 

whether Harquahala and Arlington Valley should be singled out from their other 

counterparts who are also interconnected at Hassayampa, merely because they reside in 

a generation-only balancing authority area.67

54. Solomon/Arenchild state that the proposal to conduct indicative screens for 

multiple interconnected balancing authority areas appears to merely create multiple 

opportunities for the generator in a generation-only balancing authority area to fail an 

indicative screen. Solomon/Arenchild further state that in proposing that each generator 

consider multiple relevant balancing authority areas, it seems that the Commission is 

acknowledging the highly interconnected nature of the region (a key reason for the 

existence of a “hub”), while still rejecting the proposition that a “hub” itself can be a 

 

67 Id. at 17.
Docket No. RM14-14-000 33

relevant market. Solomon/Arenchild explain that it is worth noting that in the Western 

Interconnection (unlike in the Eastern Interconnection), load flow models such as those 

underlying the SIL analyses are based not on individual balancing authority areas, but on 

“areas” that more closely approximate real world conditions.68

55. Solomon/Arenchild state that the proposal could have significant market-distortive 

effects. Solomon/Arenchild postulate that if a generator fails an indicative screen in the 

Salt River Project balancing authority area, but not in the Arizona Public Service 

balancing authority area, the Salt River Project balancing authority area may lose 

opportunities to purchase at market-based rates, and generators may lose opportunities to 

sell at market-based rates. Solomon/Arenchild contend that this would not occur if 

somewhat broader markets are considered. Solomon/Arenchild conclude that, in the 

absence of creating broader markets for generation-only balancing authority areas like 

those at Hassayampa, the Commission should not change its current practice. That is, 

sellers in generation-only balancing authority areas should use as the default relevant 

market, the directly interconnected balancing authority areas and that the scope of such 

definitions be evaluated on a case-by-case basis.69

56. Lastly, Solomon/Arenchild request that the Commission clarify that, to the extent 

that a seller fails the indicative screens in the balancing authority area(s) to which it is 

 

68 Id. at 17-18 (noting that Western Electricity Coordinating Council transmission 

models used an “Area 14,” which covers the Arizona “region” as the basis for SIL studies 

rather than the individual balancing authority areas).

69 Id. at 18.
Docket No. RM14-14-000 34

directly interconnected, sales at the “hubs” be treated as “at the metered boundary” of a 

seller’s mitigated balancing authority area, and hence, allow market-based rate sales at 

the hubs.70

57. Romkaew Broehm and Gerald A. Taylor (Broehm/Taylor) agree with the 

Commission’s logic in proposing to define relevant markets as the balancing authority 

areas that are directly interconnected to the generation only-balancing authority area. 

However, Broehm/Taylor encourage the Commission to look beyond its default market 

rule when defining a proper relevant geographic market for a market power analysis for 

all sellers. Broehm/Taylor question whether a seller’s home balancing authority area 

and its first-tier balancing authority area would be adequate for determining relevant 

default markets. According to Broehm/Taylor, during the 2000-2001 Western power 

crisis experience, suppliers with generation more than two wheels away could easily 

reach the California buyers and became pivotal sellers, simply by having firm 

transmission rights at the key interfaces.71 Broehm/Taylor explain that if the 

Commission were to require sellers to report all of their transmission reservation data, a 

seller with reservations on a path from a first-tier to a second-tier balancing authority 

area would need to perform a market power analysis for the second-tier balancing 

authority area.72 Broehm/Taylor state that this suggests that the Commission should 

 

70 Id.

71 Broehm/Taylor at 3.

72 Id. at 3-5.
Docket No. RM14-14-000 35

expand its review to consider other information, such as sellers’ transmission reservation 

data. Broehm/Taylor therefore recommend that the Commission require all sellers to 

summarize their historical short-term trade patterns outside their home balancing 

authority area and report their firm transmission service reservations of one month or 

longer as part of their triennial updated market power analysis filing. Broehm/Taylor 

state that sellers are required to report this information to the Commission via EQRs and 

that this information can be used to determine whether or not the default geographic 

markets as defined by the Commission are adequate for purposes of market power 

analyses.73

58. EPSA generally supports the proposal, but suggests consistent treatment in the 

Commission’s evaluation of nested balancing authority areas. It requests that the 

Commission clarify that it will implement the proposal in such a manner to ensure that 

as long as there is network deliverability from the nested balancing authority areas 

through the interconnected balancing authority areas and to the first-tier balancing 

authority areas, those first-tier balancing authority areas should be included in the 

indicative screens of sellers in the generation-only balancing authority areas. According 

to EPSA, this approach would more accurately reflect the geographic area in which the 

energy from the nested balancing authority area is available and with which it can 

 

73 Id. at 5-6.
Docket No. RM14-14-000 36

compete. They also state that this approach would be consistent with the analysis for an 

IPP’s balancing authority area that is connected to a trading hub.74

59. NRG Companies request that the Commission clarify that if a seller in a 

generation-only balancing authority area fails the indicative market power screens and 

surrenders or loses market-based rate authorization to sell in one or more of the markets 

connected to the trading hub, the seller will still be allowed to make market-based rate 

sales at the trading hub, as long as it retains market-based rate authorization in at least 

one of the balancing authority areas interconnected to the trading hub. NRG Companies 

state that such clarification is consistent with the Commission’s holding in Order No. 

697 that a seller that has lost market-based rate authorization and is making sales subject 

to cost-based mitigation may continue to “make market-based rate sales at the metered 

boundary between a mitigated balancing authority area and a balancing authority in 

which the seller has market-based rate authority.”75

60. EEI encourages the Commission to clarify that IPPs connected to a hub would 

need to perform the market power analyses only for the home market of each 

transmission provider connected to the hub, not the transmission provider’s first-tier 

adjacent markets, and that the IPPs could conduct a single analysis, not separate ones for 

each provider’s market. EEI also requests the Commission consider whether a similar 

 

74 EPSA at 6.

75 NRG Companies at 12-13 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252

at P 817).
Docket No. RM14-14-000 37

approach could be used for entities that are not IPPs and for entities that have a de

minimis amount of load in their balancing authority areas.76

c. Commission Determination

61. We adopt the NOPR proposal to define the default relevant geographic market(s) 

for an IPP located in a generation-only balancing authority area as the balancing authority 

areas of each transmission provider to which the IPP’s generation-only balancing 

authority area is directly interconnected. For purposes of this provision, we define an 

eligible IPP as a generation resource that has power production as its primary purpose, 

does not have any native load obligation, is not affiliated with any transmission owner

located in the target or first-tier markets in which the IPP is competing and does not have 

an affiliate with a franchised service territory.77 

62. We also adopt the proposal for such an IPP to study all of its uncommitted 

generation capacity from the generation-only balancing authority area in the balancing 

authority area(s) of each transmission provider to which it is directly interconnected. We 

clarify that we do not consider other generation-only balancing authority areas to which 

an IPP may be interconnected to be balancing authority areas of transmission providers. 

If an IPP is located in a generation-only balancing authority area that is embedded within 

a transmission provider’s balancing authority area, and that balancing authority area is 

 

76 EEI at 9.

77 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 49 n.50. This IPP could also have an 

OATT waiver on file with the Commission or qualify for a blanket waiver under 18 CFR 

35.28(d).
Docket No. RM14-14-000 38

the only balancing authority that the IPP’s generation-only balancing authority area is 

directly interconnected with, then the IPP only needs to study that transmission 

provider’s balancing authority area. An IPP in this situation would not need to study the 

transmission provider’s first-tier markets. An example of this situation is NaturEner 

Power Watch, LLC (NaturEner), which has a generation-only balancing authority area 

that is located within the NorthWestern Energy balancing authority area. NaturEner 

would provide indicative screens that examine all of its uncommitted capacity in the 

NorthWestern Energy balancing authority area. NaturEner would not need to study itself 

in any other balancing authority areas unless its generation-only balancing authority area 

is directly interconnected to other balancing authority areas.

63. Similarly, if the IPP is located in a generation-only balancing authority area and is 

not embedded within a single transmission provider’s balancing authority area, the IPP 

would need to provide indicative screens for the balancing authority area(s) of the 

transmission provider(s) to which its generation-only balancing authority area is directly

interconnected. For example, if it were the case that the generation-only balancing 

authority areas of the Gila River Power Company LLC and Sundevil generation plants 

are each directly interconnected with the balancing authority area operated by Arizona 

Public Service Co. (APS), then each of those IPPs would study themselves in the APS 

balancing authority area, and each would treat all other competing generators from 

generation-only balancing authority areas directly interconnected with the APS balancing 

authority area as being in the APS balancing authority area. The IPPs in generation-only 

balancing authority areas would also study themselves in the same manner in any other 
Docket No. RM14-14-000 39

balancing authority areas to which their generation-only balancing authority area is 

directly interconnected.78 An IPP in this situation would not need to study any of the 

transmission providers’ first-tier markets, just as would be the case if it were a generator 

located within the transmission provider’s home balancing authority area.79

64. Finally, we adopt the proposal to require an IPP in a generation-only balancing 

authority area that is directly interconnected to a transmission provider at a trading hub to 

provide indicative screens that study itself in the balancing authority area of each 

transmission provider that is directly interconnected at the trading hub80 and to assume 

that all of its uncommitted capacity may compete in each of those balancing authority 

areas.

81

 If the uncommitted capacity of an IPP studying a balancing area authority 

directly interconnected to a trading hub exceeds the transmission provider’s SIL, then the 

 

78 However, the transmission provider, in all cases, would consider the IPP 

generation capacity as first-tier generation when conducting its SIL studies and indicative 

screens.

79 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217. 

80 As noted in the NOPR, when we state that the transmission providers’ balancing 

authority areas are directly interconnected at the hub we are assuming that all such 

balancing authority areas are directly interconnected with each other. NOPR, FERC 

Stats. & Regs. ¶ 32,702 at P 56 n.58.

81 For example, if an IPP in a generation-only balancing authority area in the 

desert southwest is directly interconnected to a transmission provider at the Palo Verde 

trading hub at the Palo Verde and Hassayampa switchyards, then the IPP would provide 

screens that study all of its uncommitted capacity in each balancing authority area that is 

directly interconnected at the trading hub. An IPP in this situation would not need to 

study any markets that are first-tier to the various balancing authority areas that are 

directly interconnected at the trading hub.
Docket No. RM14-14-000 40

capacity assumed available to compete in that balancing authority area will be equal to 

the SIL. 

65. We appreciate the concerns of Solomon/Arenchild that this requirement is overly 

burdensome, but think the proposal achieves an appropriate balance. Historically, these 

sellers frequently failed the indicative screens for their home markets since they often 

own or control the majority of installed capacity, but have no associated load from which 

to reduce their market shares. The Commission’s approach in this Final Rule likely will 

obviate the need to submit a DPT to rebut the presumption of market power that results 

from failure of the indicative screens, which typically is more burdensome and expensive 

than preparing indicative screens for multiple markets. In addition, the obligation to 

submit screens for all balancing authority areas directly interconnected to a trading hub 

would apply to a limited number of market-based rate sellers and these sellers could rely 

on previously-accepted studies to complete their indicative screen analyses. We believe 

that this approach helps sellers by providing explicit guidance on the definition of the 

default market for their specific situation. 

66. In response to Solomon/Arenchild’s concern that a transmission provider would 

need to conduct two SIL studies, we clarify that SIL studies should consider the IPP’s 

generation capacity as first-tier generation to each balancing authority area studied. 

There would be no need to conduct a second SIL study that assumes that the IPP is 

located within a transmission provider’s balancing authority area. However, if an IPP has 

a long-term firm transmission reservation into a particular transmission provider’s 

balancing authority area for all or a portion of its output, then the SIL study would have 
Docket No. RM14-14-000 41

to reflect the fact that the IPP’s generation capacity associated with the transmission 

reservation would be a firm import to that specific transmission provider. However, 

multiple SIL studies would not need to be performed; in this case, the IPP’s generation 

capacity associated with the transmission reservation would be modeled as a firm import 

to the relevant transmission provider’s balancing authority area. 

67. With regard to requests that the Commission clarify that, to the extent a seller fails 

the indicative screen in the balancing authority area(s) it is directly interconnected to, 

sales at hubs are treated as “at the metered boundary”82 of a seller’s mitigated balancing 

authority area, and hence, market-based rate sales at hubs are allowed, we clarify as 

follows. An IPP would be allowed to make market-based rate sales at a trading hub if it 

loses market-based rate authority in one of the markets connected to the trading hub, so 

long as the hub is not located within the market in which the IPP is prohibited from 

selling.83

68. We find Broehm/Taylor’s request that the Commission require all market-based 

rate sellers to report their historical sales and transmission reservation data and to use 

such data to define the relevant geographic market, including markets beyond the first-

 

82 Mitigated sellers are allowed to make market-based rate sales for export at the 

metered boundary between a mitigated balancing authority area and a balancing authority 

area in which the seller has market-based rate authority. See Order No. 697, FERC Stats. 

& Regs. ¶ 31,252 at PP 819-821.

83 Resale of any sort by an affiliate of the mitigated seller into the seller’s 

mitigated balancing authority area(s) (i.e., by looping power through adjacent markets) 

are violations of a Commission-approved tariff that may also, depending on the facts, 

violate the Commission’s market manipulation regulations. See id. P 831.
Docket No. RM14-14-000 42

tier, to be outside the scope of this rulemaking. This aspect of the NOPR proposal is 

limited to the relevant geographic market for IPPs in generation-only balancing authority 

areas. 

69. We interpret EPSA’s reference to nested balancing authority areas to mean 

generation-only balancing authority areas that are embedded within a transmission 

provider’s balancing authority area. With regard to EPSA’s request to require IPPs in 

generation-only balancing authority areas to provide indicative screens for first-tier 

balancing authority areas when there is network deliverability from the embedded

balancing authority area through the interconnected balancing authority area to the firsttier balancing authority areas, we reiterate that an IPP in this situation would not need to 

study the transmission provider’s first-tier markets, even if there is available 

transmission capacity. As noted above, if an IPP is located in a generation-only 

balancing authority area that is embedded within a transmission provider’s balancing 

authority area, and that balancing authority area is the only balancing authority that the 

IPP’s generation-only balancing authority area is directly interconnected with, then the 

IPP only needs to study that transmission provider’s balancing authority area.

70. We clarify, in response to the request from Solomon/Arenchild, that the 

Commission’s proposal also is meant to apply to quasi-generation-only balancing 

authority areas such as Ohio Valley Electric Corporation, Alcoa Power Generating, Inc.-

Yadkin Division and Electric Energy Inc. We interpret EEI’s request for the 

Commission to consider applying the proposal to entities that are not IPPs and entities 
Docket No. RM14-14-000 43

that have a de minimis amount of load in their balancing authority areas to also be 

referring to quasi-generation-only balancing authority areas.

71. In response to EEI’s request, we clarify that an IPP in a generation-only balancing 

authority area that is directly interconnected to a hub would need to perform the market 

power analyses only for the home market of each transmission provider connected to the 

hub, not the transmission provider’s first-tier adjacent markets. However, we decline to 

grant EEI’s request to allow IPPs to provide a single analysis for all balancing authority 

areas interconnected to the trading hub and Solomon/Arenchild’s similar request for 

broader markets to be considered. Preparing a single analysis for all balancing authority 

areas interconnected to a trading hub would require that these areas be combined into a 

single, consolidated market. We believe that such a request is beyond the scope of this 

proceeding.

84

 

4. Reporting Format for the Indicative Screens and SIL Submittals 

1 and 2

a. Commission Proposal

72. When submitting indicative screens as part of a horizontal market power analysis, 

sellers are required to use the standard screen formats adopted by the Commission in 

 

84 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 268 (“[a]ny proposal to 

use an alternative geographic market (i.e., a market other than the default geographic 

market) must include a demonstration regarding whether there are frequently binding 

transmission constraints . . . that prevent competing supply from reaching customers 

within the proposed alternative geographic market.”).
Docket No. RM14-14-000 44

Order Nos. 697 and 697-A, which are provided in Appendix A to Subpart H of Part 35.85 

Although sellers currently submit their indicative screens using the standard formats, they 

perform their own mathematical calculations. In the NOPR, the Commission noted that 

in Puget Sound Energy, Inc.86 the Commission adopted standardized formats for 

reporting SIL study results, which includes Submittal 1, a spreadsheet that calculates the 

SIL values to be used in the indicative screens. However, the Commission noted in the 

NOPR that the current standard screen formats for indicative screens does not have a row 

for SIL values even though the Uncommitted Capacity Import values are constrained by 

the SIL values from row 10 of Submittal 1 used to report SIL study results. 

73. Thus, the Commission proposed to amend the indicative screen reporting formats

in Appendix A of Subpart H of Part 35. The Commission proposed that Appendix A 

include new rows for SIL Values, Long-Term Firm Purchases (from outside the study 

area), and Remote Capacity (from outside the study area) in both the pivotal supplier and 

market share screen reporting formats. The Commission stated that including a row in 

the indicative screens for SIL Values will help reinforce the relationship between 

affiliated and non-affiliated generation capacity imports and the SIL value. The 

Commission also proposed to modify the descriptive text of the rows in the indicative 

 

85 The Commission noted in the NOPR that the market share screen was 

inadvertently deleted from Appendix A to Subpart H of Part 35 at the time that the 

Commission made a correction to the pivotal supplier screen in Order No. 697-A. 

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 42 n.39.

86 135 FERC ¶ 61,254 (2011) (Puget).
Docket No. RM14-14-000 45

screens for Installed Capacity, Long-Term Firm Purchases, Long-Term Firm Sales, and 

Uncommitted Capacity Imports.87 The Commission stated that the new rows and their 

descriptions will clarify whether the resources are either inside or outside the study area 

for Installed Capacity and Long-Term Firm Purchases. Furthermore, the description for 

Uncommitted Capacity Imports will now be consistent across both indicative screens. 

The Commission provided an example of the proposed new indicative screens reporting 

formats in Appendix A of the NOPR.

74. The Commission proposed to revise the regulations at 18 CFR 35.37(c)(4) to 

require sellers to file the indicative screens in a workable electronic spreadsheet format.

88

 

The Commission also proposed to post on the Commission’s website a pre-programmed 

spreadsheet as an example that sellers may use to submit their indicative screens.89

75. Next, the Commission proposed to add a paragraph to the end of section 35.37(c), 

making it paragraph (5), to codify the Commission’s requirement that sellers submitting 

 

87 The Commission proposed to change the phrase “Imported Power” in Rows D 

and H of the pivotal supplier screen to “Uncommitted Capacity Imports.” The 

Commission also proposed to make the same change to Row E of the Market Share 

Screen. Thus, under this proposal, all four rows in the indicative screens will have the 

same text for this field, which represents affiliate and non-affiliate uncommitted capacity 

able to be imported from the first tier.

88 “Workable electronic spreadsheet” refers to a machine readable file with intact, 

working formulas as opposed to a scanned document such as an Adobe PDF file. 

89 The Commission explained in the NOPR that if a seller chooses to create its 

own workable electronic spreadsheet, the file it submits must have the same format as the 

sample spreadsheet on the Commission website.
Docket No. RM14-14-000 46

SIL studies adhere to the direction and required format for Submittals 1 and 2 found on 

the Commission’s website90 and submit their information, as instructed, in workable 

electronic spreadsheets.

b. Comments

76. APPA/NRECA and Golden Spread state that they support requiring sellers to file 

the indicative screens in a workable, electronic spreadsheet format.91 EEI states that to 

the extent that the Commission’s proposal simply reflects the Commission’s current 

requirements for conducting the indicative screens and Puget submittal analyses, the 

changes are appropriate and reasonable.92

77. EEI requests that the Commission specify that it simply wants market-based rate

sellers to file the information electronically using standard formats such as Adobe, Excel, 

or Word. EEI adds that if the Commission has something more complex in mind, it 

should explain the need for a more complex approach and should work with the regulated 

community in developing the new formats that will be posted on the FERC website, and 

in preparing other such guidance, information, and requirements related to the market-

 

90 The sample spreadsheets for Submittals 1 and 2 are found at the Commission’s 

website at http://www.ferc.gov/industries/electric/gen-info/mbr/authorization.asp under 

“Quick Links.”

91 APPA/NRECA at 4; Golden Spread at 7.

92 EEI at 9.
Docket No. RM14-14-000 47

based rate program, to ensure that all are reasonable, clear, accurate, easy to use, and 

most cost-effective.93

78. Solomon/Arenchild state that the proposal to require sellers to provide a summary 

spreadsheet of the SIL components used to calculate the SIL values in the electronic 

spreadsheet format provided on the Commission’s website is potentially helpful but seek 

clarification as to whether only Line 10 of Submittal 1 is required to be filed publicly.94

79. El Paso commends the proposal to add new rows to clearly identify Long-Term 

Firm Purchases and Remote Capacity from outside the study area. It states that these 

reporting modifications will not only provide clarity and transparency for the 

Commission’s review, but will also correctly recognize traditional entities, like El Paso, 

which have invested in remote generation capacity to serve their native load customers.95

El Paso states that the Commission should extend its proposal further and apply it to the 

study of first-tier balancing authority areas. El Paso states that the Commission’s 

proposed modifications to the standard screen formats in Appendix A do not consider 

when a seller with remote generation performs the analysis for the balancing authority 

areas market where its remote generation is located. El Paso recommends that the 

Commission extend its proposal to modify the horizontal screen formats to add the 

following rows to the screen formats in Appendix A: (i) “Seller Native Load outside the 

 

93 Id. at 9-10.

94 Solomon/Arenchild at 11-12.

95 El Paso at 2-3.
Docket No. RM14-14-000 48

study area” as a separate line in row K of the Market Share Analysis and (ii) “Amount of 

Seller Load outside the study area attributable to Seller Capacity inside the study area, if 

any” as a separate line in row N of the Pivotal Supplier Analysis.96

c. Commission Determination

80. We adopt the NOPR proposal to amend the indicative screen reporting formats in 

Appendix A of Subpart H of Part 35 to include new rows for SIL Values, Long-Term 

Firm Purchases (from outside the study area), and Remote Capacity (from outside the 

study area) in both the pivotal supplier and market share screen reporting formats. We 

also adopt the NOPR proposal to revise the regulations at 18 CFR 35.37, as proposed in 

the NOPR, to require sellers to file the indicative screens in a workable electronic 

spreadsheet format and to codify the requirement that sellers submitting SIL studies 

adhere to the direction and required formats for SIL Submittals 1 and 2 found on the 

Commission’s website and submit their information in workable electronic spreadsheets. 

The adopted indicative screen reporting formats for Appendix A to Subpart H is provided 

in Appendix A of this Final Rule. 

81. In response to EEI’s request that the Commission specify that it simply wants 

market-based rate sellers to file the information electronically using standard formats 

such as Adobe, Excel, or Word, we clarify that Excel or another spreadsheet format will 

be acceptable but an Adobe PDF file will not be acceptable. As the Commission stated in 

the NOPR, a “workable electronic spreadsheet” refers to a machine readable file with 

 

96 Id. at 3-4.
Docket No. RM14-14-000 49

intact, working formulas as opposed to a scanned document such as an Adobe PDF file. 

If a seller chooses to create its own workable electronic spreadsheet, the file it submits 

must have the same format as the sample spreadsheet on the Commission website.97 

82. In response to Solomon/Arenchild’s request that the Commission clarify whether 

only row 10 of Submittal 1 is required to be filed publicly, we clarify that the 

Commission expects that all of Submittal 1, not just row 10, will be filed publicly. 

Submittal 1 provides summary numeric data showing how the SIL values were calculated 

for a given relevant geographic market and some of this data already is publicly 

available. While we discourage submitting any portion of Submittal 1 as privileged, to 

the extent a filer intends to request privileged treatment for any portion of Submittal 1 or 

any other portion of its filing, such filing must comply with 18 CFR 388.112, including 

the justification for privileged treatment, i.e., why the information is exempt from 

disclosure under the mandatory public disclosure requirements of the Freedom of 

Information Act, 5 U.S.C. 552 (2012).

83. We believe there is no need to expand the indicative screens as proposed by El 

Paso because the scenario El Paso describes can be addressed within the screens, as 

 

97 It must have one worksheet for each of the indicative screens and each screen 

must have the same exact rows, columns, and descriptive text as the sample worksheets. 

Cells requiring negative values must be pre-programmed to only allow negative values. 

Likewise, cells with calculated values must contain a working formula that calculates the 

value for that cell. The file must be submitted in one of the spreadsheet file formats 

accepted by the Commission for electronic filing. The list of acceptable file formats can 

be found at the Commission’s website: http://www.ferc.gov/docs-filing/elibrary/acceptfile-formats.asp. 
Docket No. RM14-14-000 50

amended by this Final Rule. However, we clarify that a seller with remote generation 

serving the seller’s home balancing authority area (rather than serving the balancing 

authority area where the generation is physically located) should account for that 

generation capacity in row C “Long-Term Firm Sales (in and outside the study area)” if 

that generation is used to serve load in the seller’s home study area by virtue of dynamic 

scheduling and/or long-term firm transmission reservations. If the seller’s remote 

generation is not committed to serving load in the seller’s home balancing authority area, 

then that generation should be studied as uncommitted generation in the first-tier 

balancing authority area where it is located. 

5. Competing Imports

a. Commission Proposal

84. In the NOPR, the Commission noted that it permits sellers to make simplifying 

assumptions, where appropriate, and to submit streamlined horizontal market power 

analyses. The Commission noted that Order No. 697 provided that “‘a seller, where 

appropriate, can make simplifying assumptions, such as performing the indicative 

screens assuming no import capacity or treating the host balancing authority area utility 

as the only other competitor.’”98 In the NOPR, the Commission clarified that the phrase 

“assuming no import capacity” means that a seller may assume “no competing import 

capacity” from the first-tier area (i.e., directly interconnected balancing authority areas 

 

98 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 66 (quoting Order No. 697, FERC 

Stats. & Regs. ¶ 31,252 at P 321).
Docket No. RM14-14-000 51

or markets).99 The Commission further clarified that the seller must still include any 

uncommitted capacity that it and its affiliates can import into the study area.

b. Comments

85. EEI, APPA/NRECA, and Golden Spread support the Commission’s proposed 

clarifications regarding sellers performing simplified indicative screens assuming no 

competing import capacity.100

c. Commission Determination

86. We confirm the Commission’s clarification in the NOPR regarding competing 

import capacity. Specifically, “assuming no import capacity” means that a seller may 

assume “no competing import capacity” from the first-tier markets (i.e., adjacent 

balancing authority areas or markets). This clarification is consistent with the April 14, 

2004 Order101 and other Commission orders.102 The seller must still include any 

uncommitted capacity that it and its affiliates can import into the study area.

 

99 Id. P 67 (emphasis in original).

100 EEI at 10; APPA/NRECA at 4; Golden Spread at 7.

101 AEP Power Marketing, Inc. et al., 107 FERC ¶ 61,018, at P 38 (April 14 

Order), order on reh’g, 108 FERC ¶ 61,026 (2004) (“Where appropriate, the screens 

allow the applicant to submit streamlined applications or to forego the generation market 

power analysis entirely and, in the alternative, go directly to mitigation. For example, if 

an applicant would pass the screens without considering competing supplies from 

adjacent control areas, the applicant need not include such imports in its studies.”

(emphasis added)).

102 See, e.g., Acadia Power Partners, LLC et al., 107 FERC ¶ 61,168, at P 12 

(2004) (“We remind applicants that they may provide streamlined applications, where 

appropriate, to show that they pass both screens. For example, if an applicant would pass 

 (continued...)
Docket No. RM14-14-000 52

6. Capacity Ratings

a. Commission Proposal

87. In the NOPR, the Commission noted that it allows sellers submitting indicative 

screens to rate their generation facilities using either nameplate or seasonal capacity 

ratings. The Commission stated that Order No. 697 allows sellers with energy-limited

resources, such as hydroelectric and wind generation facilities, to provide an analysis 

based on historical capacity factors reflecting the use of a five-year average capacity 

factor, including a sensitivity test using the lowest and highest capacity factors for the 

previous five years. The Commission noted that since the issuance of Order No. 697, the 

Commission has recognized that sellers with newly-built energy-limited generation 

facilities may not have five years of historical data and has allowed the use of the five 

most recent years of regional average capacity factors from the Energy Information 

Administration (EIA) to determine capacity factors for those resources.

88. In the NOPR, the Commission proposed to identify solar technologies as energylimited generation resources and to allow such sellers to use either nameplate capacity or 

five-year historical average capacity ratings to determine the capacity rating for their 

solar technology generation resources. The Commission stated that similar to other 

energy-limited generation resources, sellers using the five-year average capacity factor 

must include sensitivity tests using the lowest and highest capacity factors for the 

 

both screens without considering competing supplies imported from adjacent control 

areas, the applicant need not include such imports.” (emphasis added) (footnote 

omitted)).
Docket No. RM14-14-000 53

previous five years. The Commission proposed that sellers with energy-limited 

generation facilities (including solar technologies) that do not have five years of historical 

data may use nameplate capacity, or the EIA-derived, regional capacity factor for the 

previous five years appropriate to their specific technology as defined in the EIA 

publication Annual Energy Outlook,

103 but may not use seasonal ratings.104

 For sellers 

using EIA-derived estimates, the Commission proposed to require that sellers submit 

their calculation of the regional capacity factor as well as copies of the appropriate tables 

of regional generation capacity ratings from EIA’s Annual Energy Outlook in their filing. 

89. In addition, the Commission sought industry input in identifying additional 

technologies that are energy-limited generation resources, and what capacity factors 

should be used to rate them. The Commission acknowledged that solar photovoltaic 

facilities will effectively function with zero capacity during nighttime hours or during 

heavy overcast conditions, as the sun does not provide much, if any, solar energy from 

 

103 See EIA, Annual Energy Outlook (May 2014), available at

http://www.eia.gov/forecasts/aeo/source_renewable.cfm.

In Table 58 through Table 58.9 “Renewable Energy Generation by Fuel – (by Area),” 

EIA provides data for the total generating capacity, and actual (or estimated) electricity 

generated by renewable type for 22 “electricity market module regions” covering the 

lower 48 states. After converting the inputs into matching units, sellers can divide actual 

(or estimated) electricity generated by installed capacity to find the capacity factor.

104 The Commission stated that sellers should use either nameplate, a five-year 

average of historical data, or EIA-derived five-year average regional capacity factors 

instead of seasonal capacity factors for energy-limited resources. The Commission noted

that a five-year average wind capacity factor derived from EIA regional data was an 

appropriate proxy for wind generators that do not have five years of historical data.
Docket No. RM14-14-000 54

solar photovoltaic facilities during such conditions. Thus, the Commission sought

comment on whether these operating characteristics warrant establishing a different 

method of setting capacity factors for solar generation as compared to other generation 

technologies.

90. Also in the NOPR, the Commission proposed to clarify that, within each filing, a 

seller must use the same capacity rating methodology for similar generation assets. The 

Commission stated that if a seller chooses in a particular filing to use seasonal ratings for 

one of its thermal units, it must use seasonal ratings for all of its thermal units in that 

filing. Likewise, if the seller chooses to use an alternative rating methodology, such as 

the five-year average for any energy-limited generation resource, it must use the five-year 

average for all energy-limited generation resources in that filing for which five years of 

historical data is available; otherwise it must use the EIA-derived capacity factors for 

those resources for which the seller does not have five years of data. The Commission 

stated that the seller must specify in the filing’s transmittal letter or accompanying 

testimony, and in the generation asset appendix, which rating methodologies it is using. 

The seller must use the specified rating methodologies consistently throughout its entire 

filing, including in its transmittal letter, asset appendix, and indicative screens. The 

Commission noted that this proposal does not preclude the seller from using a different 

capacity rating methodology for each type of generation facility (thermal or energy

limited) in subsequent filings (e.g., in its initial filing a seller may use nameplate ratings 

for its thermal units, then in its next filing choose to use seasonal ratings for its thermal 

units). 
Docket No. RM14-14-000 55

b. Comments

i. Identify Solar as Energy Limited

91. Many commenters support the Commission’s proposal to identify solar 

technologies as energy-limited generation resources.105 

ii. Use of Capacity Factors

92. E.ON agrees with the Commission’s proposal to allow a seller that owns or 

controls solar technology generating resources to use either nameplate capacity or fiveyear historical average capacity ratings to determine capacity rating, and to use EIAderived, regional capacity factor estimates if the seller does not have five-year historical 

capacity data. EEI asks the Commission to consider allowing a given seller, with or 

without five years of historical data, to use an alternative to the EIA regional capacity 

ratings if the seller can demonstrate that the alternative is more accurate as to one or more 

of the specific solar-generation facilities at issue in the filing, while allowing use of 

actual or historical data for other facilities in the same market. 

93. Many commenters sought clarification on the Commission’s proposals regarding 

use of capacity factors for energy-limited resources. E.ON seeks clarification that if the 

seller relies on EIA-derived capacity factors for a solar resource, it is not precluded from 

using actual historical five-year data to establish capacity factors for its other energylimited resources.106

 SoCal Edison requests clarification as to the calculation of the five-

 

105 See, e.g., E.ON at 4; NextEra at 6; EEI at 11; SunEdison, Inc. (SunEdison) at 1.

106 E.ON at 5.
Docket No. RM14-14-000 56

year average capacity factor for a given triennial; specifically, what periods do the five 

years cover, and what is the average, is it by unit or technology.107 SoCal Edison also 

asks if the EIA-derived capacity factor is used, whether it is to apply to nameplate 

capacity or seasonal ratings.

108

 EEI requests that the Commission clarify that companies 

can use the average of the data available in the EIA data tables, up to a maximum of a 

five-year average.

109

 SoCal Edison strongly supports allowing a seller to use nameplate 

capacity ratings anytime a seller is required to file only an asset appendix.

94. Broehm/Taylor state that the Commission should require use of the average 

historical capacity factor of existing energy limited resources with the same technologies 

within the same region instead of the EIA-derived, regional capacity factor estimates 

proposed by the Commission. Broehm/Taylor state that the EIA-derived, regional 

capacity factor estimates are an annual average value that does not reflect seasonality, 

thereby creating a disconnect with the Commission’s indicative screens, which are 

required to be performed on a seasonal basis. Broehm/Taylor further state that 

generation patterns for certain energy limited resources such as solar and wind may vary 

by months and seasons in certain locations.

110

 

107 SoCal Edison at 15-16.

108 Id. at 16.

109 EEI at 12 (noting that some of the EIA tables only cover 2011 forward, so five 

years of EIA data might not be available).

110 Broehm/Taylor at 6.
Docket No. RM14-14-000 57

95. Further, Broehm/Taylor state that they “seek Commission clarification on whether 

the availability factors111 are required to be applied only to nameplate capacity ratings of 

energy limited resources.” Broehm/Taylor ask whether the Commission’s statement 

“that sellers without five years of historical data cannot use seasonal ratings imply that 

the availability factors should not be applied to seasonal ratings.” Broehm/Taylor state 

that, if this is the case, it is appropriate to apply the same availability calculation to both 

new and existing units of energy limited resources. Broehm/Taylor caution that sellers

need to be consistent in using capacity ratings for calculating historical capacity factors

and if the capacity ratings are nameplate in the historical capacity factor calculation, 

these capacity factors should be applied to nameplate capacity ratings.

112

iii. Identifying Other Energy-Limited Resources

96. In response to the Commission’s request for industry input in identifying 

additional technologies that are energy-limited generation resources, SoCal Edison

identifies the following: hydro, wind, solar, biomass, and geothermal resources. It 

further states that it believes this list can and should be expanded as appropriate.113

 

111 Broehm/Taylor use the term “availability factors” several times. The 

Commission has never used availability factors as a basis for de-rating generation 

capacity.

112 Broehm/Taylor at 7.

113 SoCal Edison at 15.
Docket No. RM14-14-000 58

iv. Require Same Rating Methodology for All 

Resources of the Same Technology

97. NextEra states that it does not support requiring the same rating methodology for 

all resources of the same technology. To better reflect a seller’s market power, NextEra

urges the Commission to provide sellers the option in submitting indicative screens to 

reflect, if known, the historical capability for resources of the same technology and, if 

unknown, to submit EIA regional data for those specific resources.114 EEI echoes these 

concerns stating that sellers should be able to use five-year historical data for particular 

energy-limited generation resources where the sellers have the information, even as they 

may need to use a regional capacity factor for other such facilities for which they do not 

have the information.115

v. Limiting Capacity Standard to Peak Hours for 

Solar

98. FirstEnergy states that the Commission properly recognized in the NOPR that 

solar photovoltaic facilities will effectively function with zero capacity during nighttime 

hours or during heavy overcast conditions.116 FirstEnergy states that in the event that 

the Commission permits capacity ratings of solar technologies to be based on historical 

generation output rather than on nameplate ratings, such capacity ratings should be 

 

114 NextEra at 7.

115 EEI at 11.

116 FirstEnergy at 7.
Docket No. RM14-14-000 59

based on the output of such generating facilities during peak day-light hours only.117 

Idaho Power believes that using peak hours for determining solar capacity factors would 

be appropriate and would provide better data.118 Broehm/Taylor state that the 

Commission did not provide the definition of peak hours and suggests that the 

Commission give reasonable flexibility to sellers with regard to the number of peak 

hours when calculating availability factors for energy limited technologies as long as 

sellers justify their approach.119 

99. However, SoCal Edison contends that the screens are not designed for a particular 

hour or the peak hour for many types of generation, all hours should be considered when 

calculating the capacity rating.120 EPSA states that using peak hours will not provide a 

better measure of capacity for solar technology generation resources, and consistent with 

other intermittent energy resources, such as wind, a historical average capacity rating 

during peak hours would more accurately represent output of the facility incorporating 

the variability of output given environmental and weather events that affect solar 

generation resources output.121 E.ON states that it is unclear that the use of peak hours 

is appropriate. It states that these energy-limited resources can provide energy in 

 

117 Id. at 8.

118 Idaho Power at 3.

119 Broehm/Taylor at 7-8.

120 SoCal Edison at 15.

121 EPSA at 6-7.
Docket No. RM14-14-000 60

daylight hours and not necessarily only in peak-defined hours. E.ON asks that if the 

Commission ultimately adopts some limiting capacity standard, whether that is peak 

hours or otherwise, that the Commission clarify that the solar photovoltaic resource 

would not be precluded from selling energy products at market-based rates in any offpeak hours.122

 EEI states that the Commission should allow a seller to use an alternative 

to EIA regional capacity ratings if they can demonstrate that the alternative is more 

accurate as to one or more of the specific solar facilities at issue in the filing. EEI states 

that the Commission should give sellers the option to base solar capacity factors on peak 

hours rather than all hours, but should not require them to do so.123 NextEra states that 

as the horizontal market power indicative screens are intended to study peak hours, it

believes that it may be more consistent to require the nameplate capacity rating, which 

for solar technologies largely correlate to peak load times, rather than the five-year 

average capacity factor or EIA regional data.124

c. Commission Determination 

100. We adopt the NOPR proposals with certain modifications and clarifications. 

Specifically, we will allow sellers with energy-limited generation facilities to use 

capacity factors to de-rate those facilities in their market power analysis, with certain 

clarifications discussed below. We will also identify solar thermal technologies as 

 

122 E.ON at 5.

123 EEI at 11.

124 NextEra at 6.
Docket No. RM14-14-000 61

energy-limited technologies, but require the use of nameplate capacity ratings for solar 

photovoltaic units. 

i. Identify Solar as Energy Limited

101. We accept the NOPR proposal to identify solar photovoltaic and solar thermal 

facilities as energy-limited generation resources. However, as discussed below we will 

continue to require a seller to use nameplate ratings for its solar photovoltaic facilities. 

We will allow a seller to treat solar thermal facilities in the same manner as other energylimited resources. If a seller chooses to use a rating based on a five-year average capacity 

factor for solar thermal facilities in their filings, they must follow all of the requirements 

discussed in this Final Rule regarding the use of capacity factors. Further, a seller must 

use the same rating methodology for non-affiliated solar thermal facilities, as it does for 

its own solar thermal facilities.

102. For solar photovoltaic facilities we adopt NextEra’s proposal and require the use 

of nameplate capacity in the asset appendices and market power studies. As noted above, 

there was no consensus among commenters as to whether to de-rate solar photovoltaic 

facilities based on either an annual capacity factor or an on-peak capacity factor. Given 

the generation profile of solar photovoltaic facilities (i.e., output is highest during peak 

hours), we believe that use of nameplate ratings is reasonable for the purposes of the 

horizontal market power analysis. In addition, the Commission’s experience to date is 

that sellers typically use nameplate ratings for solar photovoltaic facilities in their market 

power analyses and asset appendices, so this requirement is consistent with current 

industry practice. Although we are requiring the use of nameplate capacity for solar 
Docket No. RM14-14-000 62

photovoltaic resources, we clarify that adopting the use of a limiting capacity factor, such 

as peak hours, for any generation resource, would not preclude that resource from selling 

energy products at market-based rates in off-peak hours.125

ii. Use of Capacity Factors

103. We will continue to allow a seller with energy-limited generation facilities other 

than solar photovoltaic to use capacity factors to de-rate those facilities in its market 

power analysis. For purposes of this discussion we are excluding solar photovoltaic from 

using capacity factors; as discussed above, solar photovoltaic will be rated on nameplate 

rating. We clarify that for energy-limited facilities, a seller may use either the nameplate 

capacity or a rating based on a five-year average capacity factor. When a seller chooses 

to use a certain rating methodology for an energy-limited resource, it must consistently 

use that rating methodology for that specific type of energy-limited resource in its 

market-power studies (i.e., its energy-limited facilities, and non-affiliated energy-limited 

facilities).126 A seller must specify in the filing’s transmittal letter or accompanying 

testimony, and in the applicable asset appendices, which rating methodology it is using 

for each technology. To the extent that a seller chooses to use a capacity factor, it must 

use a unit-specific, historical five-year average for any unit for which it can obtain five or 

 

125 E.ON at 5.

126 This is a change from the NOPR proposal to require that if a seller uses an 

alternative rating methodology for any energy-limited resource, it must use an alternative 

rating for all energy-limited resources. 
Docket No. RM14-14-000 63

more years of operating history, and use the EIA-derived regional capacity factor for any 

unit for which it is unable to obtain five years of operating history.

127

104. A seller must use the same capacity rating method for non-affiliated energylimited facilities that it uses to rate the capacity of its own energy-limited facilities when 

they are preparing their market-power analyses. Thus, a seller that uses nameplate 

ratings for its own energy-limited facilities should use nameplate ratings for all other 

energy-limited facilities included in their horizontal market power studies. Likewise, a 

seller that de-rate its own energy-limited facilities using five-year average capacity 

factors should de-rate non-affiliated energy-limited facilities using EIA regional average 

capacity factors in its screens and DPTs. Consistent with Order No. 697, we will 

continue to require a seller that de-rates its energy-limited facilities to include sensitivity 

tests using the lowest capacity factor in the previous five years, and the highest capacity 

factor in the previous five years.128

105. In the NOPR the Commission stated that a seller would be allowed to use different 

capacity rating methodologies in subsequent filings. However, we find here that a seller 

must use the same rating methodology in subsequent filings until the next updated 

triennial market power analysis. Thus, a seller would not be allowed to change its rating 

 

127 Sellers must use five years of historical data even if that means using data from 

multiple EIA reports. We recognize that this may necessitate sellers including years after 

the study period. However, this information is still historical and therefore consistent 

with the requirements of Order No. 697, FERC Stats. & Regs. ¶ 31,252, at PP 298-301.

128 Id. P 344.
Docket No. RM14-14-000 64

methodologies until its next updated triennial market power analysis (e.g., if a seller uses 

nameplate ratings for nuclear plants in its triennial, it must use nameplate for nuclear in 

all filings, until its subsequent triennial). If a seller is a Category 1 seller (i.e., not 

required to file an updated triennial market power analysis), it would be allowed to

change rating methodologies when its region’s transmission owners’ updated triennial 

market power analyses are due. We reject SoCal Edison’s request to allow a seller to 

switch rating methods just because it is filing an asset appendix. A seller must use the 

same rating methodology for each specific technology in all filings. We do not see this 

as more burdensome, because the capacity rating for most facilities will not change 

between filings. In fact, we believe this may be less burdensome because companies will 

not have different versions of their asset appendix. 

106. We adopt the NOPR proposal to require that a seller submit its calculations of the 

regional capacity factor as well as copies of the appropriate tables of regional generation 

capacity ratings from EIA’s Annual Energy Outlook in its filing. We also clarify that 

when using the EIA tables to calculate a regional average for energy-limited facilities, a 

seller should calculate capacity factors using the most recent five calendar years of data 

available in the tables. Further, the capacity factors should be applied per unit, to each 

generation facility and applied to the facilities’ nameplate ratings. Although we intend 

the use of EIA regional capacity factors as a simple and objective means for a seller to 

de-rate energy-limited facilities, we will allow a seller to propose alternative methods of 

de-rating such facilities in response to EEI and Broehm/Taylor’s comments. A seller 

proposing alternative methodologies must provide the data and calculations used to 
Docket No. RM14-14-000 65

derive the capacity factors to the Commission in public, non-privileged files. Further, the 

seller must also provide the EIA regional average capacity factor as a comparison and 

explain why it believes its methodology provides a more accurate capacity rating than the 

EIA regional average. We will decide on a case-by-case basis whether to accept any such 

proposed alternative methodology.

iii. Identifying Other Energy-limited Resources 

107. In the NOPR, the Commission sought industry input in identifying additional 

technologies that are energy-limited generation resources, and what capacity factors 

should be used to rate them. As discussed above, we adopt the proposal to identify solar 

thermal technologies as energy limited. However, given that the Commission only 

received one comment identifying additional technologies (other than solar) and the 

Commission did not receive any comments regarding what capacity factors should be 

used to rate additional technologies, we will not specifically identify any additional 

technologies as energy limited at this time.

7. Reporting of Long-Term Firm Purchases

a. Commission Proposal

108. In Order No. 697, the Commission stated that a seller’s uncommitted capacity, as 

calculated in the indicative screens, is determined by adding the total nameplate or 

seasonal capacity of generation owned or controlled through contract and long-term firm 

capacity purchases, minus operating reserves, native load commitments, and long-term 
Docket No. RM14-14-000 66

firm sales.129 The Commission also stated that generation capacity associated with 

contracts that confer operational control of a given facility to an entity other than the 

owner must be assigned to the entity exercising control over that facility. Therefore, 

market-based rate sellers have been required to report long-term firm purchases in row B 

of the indicative screens (Long-Term Firm Purchases) only if the purchase granted them 

control of the capacity. Similarly, for purposes of reporting a change in status, sellers 

have been required to report long-term firm capacity purchases when assessing their 

cumulative generation capacity only if such purchases confer control of such capacity to 

them.130 In the NOPR, the Commission noted that this requirement applies to long-term 

firm energy purchases to the extent that the long-term firm energy purchase would allow 

the purchaser to control generation capacity.131

109. In the NOPR, the Commission noted that the limited reporting of long-term firm 

purchases may create errors or misleading results in the indicative screens submitted by 

some sellers including incorrectly-sized markets and negative market shares for 

franchised public utilities and inconsistencies between the SIL values reported in the 

screens and the SIL values calculated for the relevant market or balancing authority area. 

The Commission noted instances where neither the seller nor the purchaser under a long-

 

129 Id. P 38.

130 See Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at PP 99-101.

131 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 73 (citing Order No. 697-B, FERC 

Stats. & Regs. ¶ 31,285 at PP 99-101).
Docket No. RM14-14-000 67

term firm power sale is attributed with the generation capacity that is used to make the 

sale because the seller deducted the capacity committed under the long-term firm power 

sale from its uncommitted capacity while the purchaser followed existing Commission 

policy and, because it did not “control” this capacity, did not include it as part of its 

uncommitted capacity.

110. The Commission proposed in the NOPR to modify the policy with respect to the 

reporting of long-term firm purchases in the indicative screens. Specifically, the 

Commission proposed to require applicants132 under the market-based rate program to 

report all of their long-term firm purchases of capacity and/or energy in their indicative 

screens and asset appendices, where the purchaser has an associated long-term firm 

transmission reservation, regardless of whether the seller has operational control over the 

generation capacity supplying the purchased power.

133

 The Commission proposed that if 

the long-term firm purchase involves the sale of energy and does not identify an 

 

132 Although we generally use the term “sellers” elsewhere in the Final Rule when 

referring to market-based rate sellers and applicants, in this section, we refer to such 

sellers as “applicants” to avoid confusion when discussing market-based rate sellers who 

are purchasers under long-term firm power purchase agreements.

133 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 79. In Vantage Wind, LLC, 139 

FERC ¶ 61,063 (2012) (Vantage Wind), the Commission directed the purchasers to report 

all long-term firm purchases if the purchase had long-term firm transmission rights 

associated with those resources. In the NOPR, the Commission assumed for purposes of 

the proposal that all long-term firm purchases necessarily have long-term firm 

transmission rights associated with them. If that is not the case, the Commission stated 

that applicants or intervenors are free to raise fact-specific circumstances that they 

believe may support a different attribution of capacity. NOPR, FERC Stats. & Regs. 

¶ 32,702 at P 79 n.97.
Docket No. RM14-14-000 68

associated capacity amount, the purchaser must convert the amount of energy to which it 

is entitled into an amount of generation capacity for purposes of its indicative screens and 

asset appendices, i.e., include the amount of the capacity as long-term firm purchases in 

rows B (Long-Term Firm Purchases (from inside the study area)) or B1 (Long-Term 

Firm Purchases (from outside the study area)) of the proposed revised indicative screens 

and include it in its asset appendix. The Commission proposed that a seller under that 

firm power purchase agreement must continue this approach the next time it submits a 

market-based rate triennial or change in status filing with the Commission, i.e., convert 

the energy into capacity and include the amount of capacity as a long-term firm sale in 

row C (Long-Term Firm Sales).134 The Commission proposed that, when making these 

 

134 In the NOPR, the Commission stated that many power purchase agreements for 

firm energy specify an associated capacity commitment from the seller. In cases where 

capacity commitments are not specified in the power purchase agreement, we propose 

that applicants use the following formula to convert energy to capacity (on a one-year 

basis): [energy (MWh) / 8,760] / capacity factor = capacity (MW).

Where energy (MWh) is the total amount of energy purchased under the 

power purchase agreement over the calendar year; 8,760 is the total hours 

of a calendar year (use 8,784 in a leap year); capacity factor is actual 

capacity factor achieved by the unit(s) supplying the energy during the 

calendar year and is a measure of a generating unit’s actual output over a 

specified period of time compared to its potential or maximum output over 

that same period. For example, if 700,000 MWh is the amount of firm 

energy purchased under a power purchase agreement during a calendar 

year, and the capacity factor of the generator supplying the energy is 0.8 or 

80 percent, then the 700,000 MWh of energy would be converted into 

approximate 100 MW of capacity. That is: (700,000 MWh / 8,760) / 0.8 = 

100 MW.

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 79 n.98.
Docket No. RM14-14-000 69

filings, both the purchaser and the seller must show how they made the energy-tocapacity conversion. Although the Commission proposed this attribution of capacity as a 

general policy, the Commission noted that applicants or intervenors may raise factspecific circumstances that they believe may support a different attribution of capacity.

111. The Commission stated that the intent of the proposed reform is to have an 

applicant report all long-term firm purchases that it makes where the selling entity has a 

legal obligation to provide the purchaser with an energy supply that cannot be interrupted 

for economic reasons or at the seller’s discretion. If the purchaser has contractual rights 

to receive the output of a long-term firm energy purchase, the Commission proposed that 

the amount of the capacity supplying that purchase must be reported in the purchaser’s 

screens. 

112. In the NOPR, the Commission stated that the proposal to require applicants to 

report all of their long-term firm purchases of capacity and/or energy in their indicative 

screens and asset appendices is supported based on several considerations. First, it will 

size the market correctly and therefore improve the accuracy of the indicative screens, 

especially for franchised public utilities, whose indicative screens are used by the nontransmission owning sellers to prepare their own indicative screens. Currently, applicants

often do not report some or all of their long-term firm purchases because they do not 

control these resources. Including all long-term firm purchases in the indicative screens 

will properly size the market and eliminate the unrealistic results (e.g., negative market 

shares) caused by the under-reporting of generation noted above.
Docket No. RM14-14-000 70

113. Second, the Commission stated that this proposed change will establish consistent

treatment of long-term firm sales and long-term firm purchases in the indicative screens. 

The Commission noted that applicants typically deduct long-term firm sales without 

making a determination as to whether those sales confer operational control to the 

purchaser. The Commission explained that, in Order No. 697, it did not require that 

sellers make such a determination before deducting the capacity supporting long-term 

firm sales: “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.”135 In Order 

No. 697, the Commission stated that “[s]ellers may deduct generation associated with 

their long-term firm requirements sales, unless the Commission disallows such 

deductions based on extraordinary circumstances.”136

114. In the NOPR, the Commission explained that it is only on the “buy” side of longterm firm purchases that the Commission has considered the issue of control in reporting 

capacity in the screens.137 The Commission stated that the result is that some generation 

capacity sold under long-term power purchase agreements “disappears” from the market 

because neither the seller nor the purchaser includes the capacity as part of its 

uncommitted capacity (i.e., the seller subtracts the amount sold under the long-term 

 

135 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 38 (footnotes omitted).

136 Id. P 38 n.18.

137 Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at PP 99, 100.
Docket No. RM14-14-000 71

power purchase agreement from its capacity for purposes of its screens, but sometimes 

the purchaser does not add the corresponding amount to its capacity for purposes of its 

screens). The Commission stated that it is inevitable that some generation capacity will 

be excluded from the indicative screens, with resulting errors in market shares and overall 

market size, when differing standards are applied to long-term firm purchases and longterm firm sales with respect to the allocation of such capacity. The Commission stated 

that the NOPR proposal will make those standards consistent, reducing such errors.

115. Third, requiring the reporting of all long-term firm power purchases also will 

ensure consistent treatment of owned or installed capacity and long-term firm purchases 

in the indicative screens. The Commission stated that the horizontal market power 

analysis implicitly assumes that applicants control all of their owned or installed capacity 

listed in their indicative screens but this is not necessarily the case.138 For example, in 

situations where an applicant is a minority owner of a jointly-owned generating unit, it is 

quite possible that the applicant will not have operational control (i.e., commitment and 

dispatch authority) over the unit.139 However, applicants typically include all of their 

 

138 As the Commission explained in the NOPR, in Order No. 697, the Commission 

noted that its historical approach has been that the owner of a facility is presumed to have 

control of the facility unless such control has been transferred to another party by virtue 

of a contractual agreement. The Commission stated in Order No. 697 that it would 

continue its practice of assigning control to the owner absent a contractual agreement 

transferring such control. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 183. 

139 Another example is when a generator confers operational control to a third 

party through a long-term tolling agreement. See, e.g., Shell Energy North America (US), 

L.P., 135 FERC ¶ 61,090, at P 3 (2011).
Docket No. RM14-14-000 72

owned or controlled generation capacity in the indicative screens regardless of whether 

they actually control the commitment and dispatch of this capacity. Accordingly, the 

Commission proposed that an applicant with long-term firm purchases treat such 

contracted-for capacity in a similar manner to an applicant that owns capacity; that is, 

such purchases should be included in the applicant’s portfolio of generation for the 

indicative screens.

116. Further, the Commission stated in the NOPR that for those applicants incorrectly 

reporting long-term firm power purchases in the wrong row of the indicative screens,140

uniform reporting of these purchases will also help to ensure consistency between the SIL 

values reported in the screens and the Commission’s accepted SIL values for the relevant 

market or balancing authority area. In the NOPR, the Commission stated that improperly 

classifying long-term firm purchases (or imports of remotely-owned installed capacity) as 

Imported Power in the existing screens (row D of the pivotal supplier screen and row E of 

the market share screen) may lead to an overstatement of the market’s SIL values.141 The 

 

140 The NOPR stated that “[a]s the Commission noted in Vantage Wind, 

improperly classifying long-term firm purchases (or imports of remotely-owned installed 

capacity) as Imported Power in the existing screens . . . may lead to an overstatement of 

the market’s SIL values.” NOPR, FERC Stats. & Regs. ¶ 32,702 at P 85 (citing Vantage 

Wind, 139 FERC ¶ 61,063).

141 The Commission noted Vantage Wind, 139 FERC ¶ 61,063 at P 16 (“In its 

updated market power analysis, Puget accounted for both its remote generation from its 

Colstrip plant located in Montana and its firm power purchase agreements from 

Bonneville Power Administration as Imported Power (Line D of the market share screen 

and the pivotal supplier screen) rather than as Installed Capacity (Line A of the market 

share screen and the pivotal supplier screen) or a Long-term Firm Purchase (Line B of the 

 (continued...)
Docket No. RM14-14-000 73

Commission explained in the NOPR that this is because the sum of the values in the 

existing pivotal supplier screen for Seller and Affiliate Imported Power shown in row D 

and Non-Affiliate Imported Power shown in row H should be less than or equal to the 

Commission-accepted SIL values. All Commission-accepted SIL values account for (i.e., 

subtract) long-term transmission reservations into the study area, so that they reflect the 

transmission capability available to competing sellers after accounting for the capability 

that the local utility has reserved for its own use to import power from remote resources. 

Thus, the Commission explained that classifying long-term firm purchases as Imported 

Power effectively “double counts” import capability in the screens because it adds back 

the import capability associated with long-term firm purchases and assumes that this 

capability is available to potential competitors. The Commission stated that this problem 

does not arise if long-term firm purchases (and imports of remotely-owned installed 

capacity) are properly classified in the indicative screens as Long-Term Firm Purchases 

(rows B1 and F1 in the proposed screen format for the pivotal screen) and Remote 

Capacity (rows A1 and E1 in the proposed screen format for the pivotal screen), 

respectively. The Commission stated that this proposal is intended to help clarify how to 

 

market share screen and the pivotal supplier screen), respectively. Consequently, the 

total SIL shown in Puget’s screens exceeded the net SIL value for the Puget balancing 

authority area as accepted by the Commission in [Puget, 135 FERC ¶ 61,254]. When 

Vantage Wind applied the Commission-approved SIL values to its analysis without 

making any other adjustments to Puget’s screens, Vantage Wind appeared to fail the 

screens because Puget’s capacity was underreported.”). 
Docket No. RM14-14-000 74

classify imports of firm power and remotely-owned capacity. The Commission also 

proposed these changes to the screen format for the market-share screen.

b. Comments

117. Commenters mostly disagree with the proposal, either supporting the 

Commission’s existing “control test” or expressing concerns that the Commission’s 

proposal does not actually make the reporting more accurate.142 SoCal Edison states that 

the Commission’s identified flaws in the control test and the current reporting of longterm purchases are not well supported and do not merit abandonment of the control 

test.143 In particular, SoCal Edison disputes the “disappearing capacity” concern raised 

in the NOPR, asserting that generation capacity associated with long-term firm sales is 

reflected in some manner in the screens.144 SoCal Edison also contends that the 

Commission’s assertion that a long-term firm purchase is just like ownership with regard 

to the ability to get energy to the market is demonstrably false in some cases.145

118. E.ON and FirstEnergy agree with the Commission’s proposal.146 FirstEnergy 

states that “attribution of all such capacity to the purchaser, as proposed by the FERC, 

 

142 EPSA at 10; APPA/NRECA at 21-24; SoCal Edison at 3-11; 

Solomon/Arenchild at 8-10; Avista at 2-4; NextEra at 8; TAPS at 2. 

143 SoCal Edison at 3.

144 Id. at 5.

145 Id. at 11. 

146 E.ON at 6; FirstEnergy at 8.
Docket No. RM14-14-000 75

will recognize appropriately the rights of the purchaser in the purchased resource and 

will help to improve the consistency of market power studies.”147 E.ON requests 

clarification that sellers of long-term capacity in RTO markets would not be required to 

submit indicative screens solely because the purchaser was required to do so.148

119. EEI urges the Commission to engage in further dialogue, noting that some EEI 

members have concerns, and some agree with at least some elements of the proposal. 

EEI states that some members were concerned that they would lose flexibility to reflect 

actual ownership and control of assets in indicative screens and asset appendices, and 

whether they would need to report the long-term contracts in the asset appendix.

149

 

120. Avista/Puget state that the Commission’s proposed solution goes too far and that 

the Commission instead should retain its current treatment of purchased capacity and/or 

energy based on the concept of operational control established in Order No. 697, with 

certain modifications to ensure that the capacity does not disappear from reports of the 

market.150 To prevent generation capacity from disappearing in the indicative screens, 

Avista/Puget propose that the Commission modify its current policy with regard to the 

seller’s treatment of sold energy such that it is the mirror image of the purchaser’s 

treatment. Under Avista/Puget’s proposal, generating capacity associated with a long-

 

147 FirstEnergy at 8-9.

148 E.ON at 7.

149 EEI at 12.

150 Avista Corp. and Puget Sound Energy, Inc. (Avista/Puget) at 2.
Docket No. RM14-14-000 76

term sale would be assigned to the seller, for purposes of conducting the indicative 

screen computations, if the contract does not convey control of the capacity to the 

purchaser.151 

121. TAPS expresses concerns that the proposed change may well result in inaccurate 

reporting and mask the market power of large sellers where they retain control over the 

resource(s).152 APPA/NRECA concede that this may fix some administrative problems, 

but worry that the resulting indicative screens will not accurately reflect actual market 

shares or pivotal supplier conditions.153

122. Indicated Utilities state that if the Commission adopts this rule, it should exempt 

from this requirement the capacity and/or energy associated with power purchase 

agreements from inherently intermittent qualifying small power production facilities 

entered into under 18 CFR Part 292, Subpart C, namely solar and wind qualifying 

facilities.

154 Indicated Utilities state that power purchase agreements with intermittent 

resource qualifying facilities are often fundamentally different from other power 

purchase agreements and thus warrant different treatment from that proposed in the 

NOPR.155 For that reason Indicated Utilities urge the Commission to retain for such 

 

151 Id. at 4.

152 TAPS at 2.

153 APPA/NRECA at 21-24.

154 Indicated Utilities at 2.

155 Id. at 5.
Docket No. RM14-14-000 77

power purchase agreements its existing policy of attributing capacity and/or energy to 

the entity that “controls” the qualifying facilities, as that term has been used in Order 

No. 697.156

123. EPSA questions the utility of this proposal and seeks clarification of how this 

requirement would differ from the reporting required in EQRs. EPSA states that it 

appears that the information required to be reported by this proposal would duplicate the 

information provided by sellers contained in the EQRs, which are required to be filed 

under current Commission regulations. EPSA suggests that if the Commission is 

seeking this information, then the Commission should not adopt the proposed revision 

but just refer to the EQR data.

157

124. EPSA requests clarification that in evaluating long-term contracts for the 

indicative screens, sellers are still permitted to make conservative assumptions in their 

initial application and triennial updated market power analyses.158

125. Indicated Utilities state that the Commission should clarify that this proposed 

change – whether for intermittent qualifying small power production facilities power 

purchase agreements or other power purchase agreements – applies only to the 

indicative screens and asset appendices, and does not apply to any DPT analyses 

submitted to rebut a presumption of market power brought about by failure of one or 

 

156 IWU at 7.

157 EPSA at 9-10.

158 Id. at 10.
Docket No. RM14-14-000 78

both of the screens. Indicated Utilities contend that it would be consistent with the 

Commission’s post-Order No. 697 approach for the proposed policy to apply only to the 

indicative screens while maintaining the current “control-based” approach to DPT 

analyses. Indicated Utilities state that the indicative screens are designed to be screens, 

while the DPT, on the other hand, is more granular and a more accurate means of 

assessing horizontal market power.159 

126. SoCal Edison states that it does not generally object to the Commission collecting 

data on all long-term firm purchases through the asset appendix, but SoCal Edison asks 

the Commission to clarify that inclusion of a long-term firm purchase in an asset 

appendix does not constitute a concession that a purchase should appear in a market 

power screen analysis. SoCal Edison states that a seller should be permitted to rebut the 

presumption that any particular long-term firm purchase should be counted if the 

applicant is seeking to exclude the long-term firm purchase from a market power 

analysis. SoCal Edison further submits that if the applicant has no obligation to submit 

such screens, it need not rebut the presumption, but reserves the right to do so if ever 

requested to submit a screen analysis.160

127. Several commenters request clarification of various aspects of the proposal. 

SoCal Edison requests that the Commission explain how the buyer is to obtain the 

capacity factor information, which may not exist, in order to convert energy-only 

 

159 Indicated Utilities at 8-9. 

160 SoCal Edison at 12.
Docket No. RM14-14-000 79

transactions.

161

 Solomon/Arenchild state that converting an energy-only contract to 

MW-equivalents rather than the full amount of capacity may create confusion. 

Solomon/Arenchild ask whether the determining characteristic is whether a capacity 

payment is part of the long-term contract.162 NextEra expresses concerns with the 

formula proposed for converting long-term energy purchases to a capacity value.163 

NextEra suggests that rather than requiring the actual energy supplied during a calendar 

year in the capacity calculation, a purchaser/seller should be allowed to rely on EIA 

regional data for energy-limited resources. NextEra states that otherwise there could be 

a significant overstatement of the capacity value submitted in triennial market power 

updates or notices of change in status.164 APPA/NRECA state that the proposed 

conversation mechanism in footnote 98 of the NOPR calculates capacity as an average 

annual number, whereas the peak capacity purchased during a shorter interval in the 

study period would be the most relevant number.

128. SoCal Edison states that although the NOPR proposes reporting of long-term firm 

purchases where the purchase has an associated long-term firm transmission reservation, 

the concept of a long-term firm transmission reservation does not exist within the 

California Independent System Operator Corporation (CAISO) market. Therefore, 

 

161 Id. at 17.

162 Solomon/Arenchild at 10-11.

163 NextEra at 9.

164 Id. at 10. 
Docket No. RM14-14-000 80

SoCal Edison states that the Commission should clarify for CAISO and any other region 

that has eliminated long-term firm reservations, how this standard should be applied.165

129. Solomon/Arenchild ask for clarification on the treatment of jointly-owned 

facilities. They state that although the NOPR proposal abandons the need to determine 

the party that controls capacity under long-term contracts, the need for letter of 

concurrence seems to remain. They state that because the letter of concurrence 

previously was tied to the issue of the degree to which each party controls a facility, and 

control is no longer a factor, it is difficult to understand when letters of concurrence are 

appropriate.166

c. Commission Determination 

130. We adopt the proposal to report long-term firm purchases in the indicative 

screens, with modification and clarifications as discussed below. We believe that 

requiring applicants under the market-based rate program to report all of their long-term 

firm purchases of energy and/or capacity, regardless of whether the applicant has 

operational control of the generation capacity supplying the purchased power, will 

improve the accuracy of the indicative screens. 

131. Some commenters contend that the proposed change will not make the screens 

more accurate because it may understate the market power of entities selling long-term 

 

165 SoCal Edison at 13.

166 Solomon/Arenchild at 11.
Docket No. RM14-14-000 81

firm capacity and/or energy.167 However, this argument overlooks the fact that sellers in 

most cases already are deducting capacity sold pursuant to long-term firm contracts. The 

differing standards applied to purchasers and sellers with respect to control are the basis 

for the “disappearing capacity” problem described in the NOPR. Furthermore, as 

explained below, the Commission believes that it is more appropriate to attribute such 

capacity to the purchaser rather than the seller.

132. We are not persuaded by SoCal Edison’s arguments disputing the existence of a 

“disappearing capacity” problem under the current policy. For example, SoCal Edison 

claims that even if an applicant does not attribute a long-term firm energy and/or capacity 

purchase to itself, the associated capacity will show up in the screens as non-affiliate 

capacity.168 This is potentially true only if the purchased capacity is located in the same 

balancing authority area or market as the purchaser because the non-affiliated capacity 

included in the indicative screens only includes capacity located in the study area.

169

 

Many of the long-term purchases reported in certain regions cross balancing authority 

areas, i.e., the purchase is made from a resource external to the purchaser’s home market. 

 

167 APPA/NRECA at 24; TAPS at 2. 

168 SoCal Edison at 5. 

169 The indicative screens include rows for long-term firm sales and purchases 

made by non-affiliated sellers. However, the existence of these rows does not support 

SoCal Edison’s argument because a long-term firm purchase made by SoCal Edison from 

a seller external to SoCal Edison’s market (CAISO) would not show up as a long-term 

firm purchase made by a non-affiliated seller in CAISO. Thus, the capacity associated 

with the long-term firm purchase that SoCal Edison did not report would not show up in 

its indicative screens for the CAISO market.
Docket No. RM14-14-000 82

Therefore, capacity associated with long-term purchases often is not included in the 

indicative screens. Moreover, not reporting a long-term firm purchase from an external 

generation resource would make the screens inconsistent with the SILs, which account 

for long-term transmission reservations. Long-term firm purchases usually have an 

associated long-term firm transmission reservation. SoCal Edison’s arguments also 

ignore the problems that can arise when an applicant’s long-term firm purchases are 

recorded in an incorrect line of the indicative screens, which the Commission noted in 

Vantage Wind170 and explained in the NOPR.

133. Avista/Puget proposes to fix the “disappearing capacity” problem by allowing 

sellers of long-term firm energy and/or capacity to only deduct such capacity in their 

indicative screens if they relinquish operational control over the capacity.171 While this 

proposal would solve the “disappearing capacity” problem, we find that it is more 

appropriate to attribute capacity from a long-term firm power purchase agreement 

accompanied by a long-term firm transmission reservation to a purchaser/load serving 

entity, rather than to the seller, because the purchaser can use that contract to meet its 

capacity requirements. The seller cannot withhold the power from the purchaser even 

though the seller has operational control over the generating unit(s) supplying the power. 

Power purchase agreements may give the purchaser significant economic control over the 

power; e.g., the purchaser can bid the energy into centralized spot markets (if present). 

 

170 Vantage Wind, 139 FERC ¶ 61,063 at P 16.

171 Avista at 4. 
Docket No. RM14-14-000 83

134. Moreover, applying the control test to the seller would largely negate the 

Commission’s policy with respect to fully committed generation capacity, as described 

elsewhere in this Final Rule. Under this policy, in order to satisfy the Commission’s 

market-based rate requirements regarding horizontal market power, sellers may explain 

that their generation capacity is fully committed in lieu of including indicative screens. 

Today, new generating units, many of which are wind and solar units, often represent that 

they are fully committed under long-term power purchase agreements and deduct all of 

their capacity in the indicative screens or do not provide screens at all. Under 

Avista/Puget’s proposal to assign the control test to the seller of long-term firm capacity, 

such sellers would only be able to deduct their capacity if they demonstrated that the 

purchaser had operational control of the generating unit. These sellers either would have 

to demonstrate that they no longer have control of their generation capacity or, if that was 

not the case, submit indicative screens. What currently are routine filings requesting 

market-based rate authority for new fully committed generators could in some cases 

become complicated.

135. We reject Indicated Utilities’ proposal to exempt applicants from reporting longterm firm purchases backed by intermittent or energy-limited qualifying facility 

resources.

172

 We believe that there is no reason to ignore such long-term firm purchases 

in the indicative screens and that Indicated Utilities’ position confuses the operational 

 

172 IWU at 7. 
Docket No. RM14-14-000 84

characteristics of such resources with operational control. The fact that a solar or wind 

unit will not produce energy at certain times is equally true whether an applicant owns a 

solar or wind unit or purchases energy from a solar or wind unit through a long-term firm 

power purchase agreement. We clarify, however, that consistent with our direction 

elsewhere in this Final Rule, long-term firm purchases backed by energy-limited 

resources may be de-rated based on a five-year average capacity factor based either on 

the unit’s operating history or the EIA regional average. Providing this capacity rating 

option to applicants will yield consistent treatment of such resources in the indicative 

screens, whether owned or purchased.173 This capacity rating option also addresses 

NextEra’s concern regarding the potential overstatement of capacity associated with 

long-term firm power purchase agreements in the indicative screens.

136. Regarding SoCal Edison’s argument concerning the distinctions between owning 

and purchasing generation, we reiterate that, for the purpose of horizontal market power 

analyses, long-term firm power purchase agreements convey rights to generation capacity 

that are similar (though not identical) to ownership because they provide the purchaser 

with a resource that the purchaser can rely on to serve its load. The common definition of 

a “firm” purchase is a service or product that is not interruptible for economic reasons.174 

This was the Commission’s primary reason for concluding in the NOPR that a long-term 

firm purchase was comparable to ownership. Such purchases provide a resource that a 

 

173 See supra Section IV.A.6.

174 The EQR Data Dictionary uses this definition as well. 
Docket No. RM14-14-000 85

load-serving entity can count towards its capacity requirement. The variable nature of 

energy-limited resources is the primary reason given by SoCal Edison for disputing the 

NOPR’s contention that long-term firm energy agreements provide the purchaser with 

energy that only can be interrupted for limited and specified reasons.175 However, as 

discussed above, the variable nature of certain energy-limited generators is a separate 

issue, and we will allow applicants to de-rate long-term firm power purchase agreements 

backed by energy-limited resources according to a five-year average capacity factor as 

discussed below. This will permit equivalent treatment of energy-limited resources in the 

indicative screens whether owned or purchased under long-term firm power purchase 

agreements.

137. With regard to EPSA’s contention that reporting of long-term firm power 

purchase agreements in the indicative screens is duplicative of reporting such transactions 

in EQRs, the indicative screens and EQRs perform separate functions. The former is an 

ex ante analysis of a seller’s potential market power while the latter enables an ex post

analysis of its sales. Information on long-term firm purchases and sales is required to 

complete the indicative screens. The need to provide this information is not “waived” 

because it also is reported after-the-fact in EQRs or other forms. Therefore, we affirm 

the need for applicants to report long-term firm purchases in the indicative screens.

 

175 SoCal Edison at 11. 
Docket No. RM14-14-000 86

138. With respect to questions raised regarding the treatment of long-term firm 

purchases in DPT analyses, we clarify that applicants must attribute long-term firm 

power purchase agreements to the purchaser when the power purchase agreement has an 

associated long-term transmission reservation. An applicant that includes long-term firm 

power purchase agreements in its screens should include the same power purchase 

agreements in any DPT analyses filed to rebut the presumption of market power resulting 

from a screen failure. The fact that DPTs are more detailed, granular market power 

analyses does not negate the need to attribute long-term firm purchases to purchasers. 

We recognize that this may lead to inconsistencies in the treatment of long-term 

purchases between DPT analyses submitted in section 203 filings and those submitted in 

section 205 filings, but there already are several differences between DPT analyses filed 

in section 203 and 205 proceedings (e.g., the section 203 analysis is a forward-looking 

analysis whereas the section 205 analysis is historical). 

139. We confirm that long-term firm power purchase agreements that are reported in 

the indicative screens also should be reported in the asset appendix, Appendix B, as 

proposed in the NOPR. However, we agree with commenters that the existing Appendix 

B is not designed to report long-term firm purchases, particularly those that are not 

backed by specific generating units. Therefore, the Commission is creating a separate 

sheet in Appendix B specifically for applicants to report all long-term firm purchases 
Docket No. RM14-14-000 87

included in their indicative screens. This new sheet to the asset appendix is described in 

the discussion of the asset appendix below.176

140. With respect to the process for converting long-term firm energy-only contracts 

to MW equivalents, we provide clarification and have decided to modify the approach set 

forth in the NOPR. First, with respect to a question raised by Solomon/Arenchild, we 

clarify that such conversions are needed only if a capacity amount (MW) is not specified 

in the contract. Long-term firm power purchase agreements that have a capacity amount 

specified need not be converted, regardless of whether the contract includes a separate 

capacity payment. 

141. Upon consideration of the comments, we will modify the energy-to-capacity 

conversion formula proposed in the NOPR. We find there is some merit to SoCal 

Edison’s argument that firm energy contracts cannot necessarily be linked to specific 

generating units (although the energy comes from a set of generating units that ultimately 

can be identified). Thus, we are adopting an alternative conversion approach that is 

responsive to these concerns; this approach is conceptually similar to the approach 

proposed in the NOPR but uses a different factor – load rather than generation – to 

convert energy into a capacity value.177

 

176 See infra Section IV.D.

177 Although we are adopting an alternative approach in the Final Rule, the 

alternative approach is a logical outgrowth of the approach proposed in the NOPR. See 

Aeronautical Radio, Inc. v. FCC, 928 F.2d 428, 445-446 (D.C. Cir. 1991) (citing United 

Steelworkers of America v. Marshall, 647 F.2d 1189, 1221 (D.C.Cir.1980), cert. denied, 

 (continued...)
Docket No. RM14-14-000 88

142. In place of the conversion formula set forth in the NOPR, applicants should use 

their actual load factor178 in the relevant study period to convert a long-term firm energyonly contract to a MW equivalent. To determine the MW equivalent, applicants should 

first determine the average MW purchased under the long-term firm energy contracts 

over the study period.179 Applicants should then divide the average MW purchased by 

their load factor to obtain the capacity value for the contract. 

143. Long-term firm energy contracts serve the purchaser’s load for a term of at least 

one year, so the purchaser’s load factor is a reasonable basis to establish the capacity 

value of a long-term firm energy contract. This approach also avoids the need to 

calculate a capacity factor and link the purchase back to a generating unit or set of 

generating units. Applicants have ready access to their load data so performing this 

conversion should not be problematic or burdensome. 

144. Applicants would continue to have the option of proposing a different method 

of attributing capacity based on the specific terms and conditions of their power purchase 

 

453 U.S. 913, 101 (1981)) (holding that the notice requirement of section 553 of the 

Administrative Procedure Act is fulfilled “so long as the content of the agency’s final rule 

is a ‘logical outgrowth’ of its rulemaking proposal.”).

178 Load factor is the average load divided by the peak load in a specified time 

period. For example, if during a calendar year a franchised public utility has a peak load 

of 2,000 MW and total sales to native load customers of 10,000,000 MWh, its load factor 

is [(10,000,000/8760)/2000] = 0.57 or 57 percent. 

179 Average MW equals total MWh purchased during the study period divided by 

the total hours in the study period. 
Docket No. RM14-14-000 89

agreement. Any alternative attribution method would have to be fully supported and 

justified.

145. We provide several clarifications to the reporting of long-term firm power 

purchase agreements. First, we clarify that an applicant should report a long-term firm 

purchase of capacity and/or energy that has an associated long-term firm transmission 

reservation for either point-to-point or network transmission service. In addition, we 

clarify that this requirement applies regardless of whether the long-term firm 

transmission reservation is held by the purchaser or seller of the capacity/energy. In 

response to SoCal Edison’s query, we clarify that the requirement that applicants only 

include long-term firm power purchase agreements in their indicative screens if they have 

an associated long-term transmission reservation will not apply within an RTO/ISO 

market if that RTO/ISO does not have long-term firm transmission reservations or their 

equivalent. Instead, applicants in such RTO/ISO markets will be required to report all 

long-term firm energy and/or capacity purchases from generation capacity located within 

the RTO/ISO market if the generation is a designated as a network resource or as a 

resource with capacity obligations. We further clarify that letters of concurrence will not

be required to establish which party to a long-term firm power purchase agreement has 

control of the underlying generation resource(s).180 

 

180 However, sellers may need to submit a letter of concurrence to support claims 

that they do not own or control the entire capacity of a generation facility. See Order No. 

697, FERC Stats. & Regs. ¶ 31,252 at P 187. 
Docket No. RM14-14-000 90

8. Clarification of Commission Language in Performing SIL 

Studies 

146. The SIL study is used in both the indicative screens and the DPT analysis as the 

basis for establishing the amount of power that can be imported into the relevant 

geographic market.181 In the NOPR, the Commission summarized previous Commission 

SIL guidance to transmission operators provided in the April 14 Order, Puget, and Order 

No. 697. The Commission noted that the April 14 Order requires that power flow 

benchmark cases reasonably simulate the historical conditions that were present182 and 

requires that sellers consider “all internal/external contingency facilities and all 

monitored/limiting facilities that were used historically to approximate area-area 

transmission availability” and utilize scaling methods according to the same methods 

used historically for non-affiliate resources.183

147. In the NOPR, the Commission noted that Puget clarified that sellers must 

“[p]rovide copies of all Operating Guide descriptions that were applied in the scaling 

section,” as well as any operating guides used to ignore limiting elements in the SIL 

 

181 Id. P 19.

182 Historical conditions include “facility/line deratings used to maintain capacity 

benefit margins (CBM) and transmission reliability (TRM/CBM), actual unit dispatch 

used to fulfill network and firm reservation obligation, the actual peak demand, generator 

operating limits opposed on all resources in real time, other limits/constraints imposed by 

the TP [Transmission Provider] during the season peaks.” April 14 Order, 107 FERC 

¶ 61,018 at app. E.

183 NOPR, FERC Stats. & Regs. ¶ 32,702 at PP 147, 151 (citing April 14 Order, 

107 FERC ¶ 61,018 at app. E).
Docket No. RM14-14-000 91

study results.184 The Commission also stated that applicants must exclude study area 

non-affiliated load from study area native load, and should not include first-tier 

generation serving study area non-affiliated load in net area interchange. In addition, the 

Commission specified that applicants must document all instances where the SIL study 

differs from historical practices.185

148. In the NOPR, the Commission also noted the Commission’s finding in Order No. 

697 that SIL studies performed by sellers “should not deviate from” and “must 

reasonable[ly] reflect” the seller’s Open Access Same-Time Information System 

(OASIS) operating practices and “techniques used must have [been] historically 

available to customers.”186 The Commission further stated that “by OASIS practices, we 

mean sellers shall use the same OASIS methods and studies used historically by sellers

(in determining simultaneous operational limits on all transmission lines and monitored 

facilities) to estimate import limits from aggregated first-tier control areas into the study 

area.”187 Furthermore, the Commission stated that Order No. 697 requires that power 

 

184 Id. P 150 (citing Puget, 135 FERC ¶ 61,254 at app. B, Reporting Requirements 

for Submittals 8, 9).

185 Id. (citing Puget, 135 FERC ¶ 61,254 at app. B, Reporting Requirements for 

Submittals 10 and 11).

186 Id. P 146 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354 

(internal citations omitted)).

187 Id. P 146 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354 n.361).
Docket No. RM14-14-000 92

flow cases “represent the transmission provider’s tariff provisions and firm/network 

reservations held by seller/affiliate resources during the most recent seasonal peaks.”188

149. The Commission noted that Order No. 697 allows the use of simultaneous total 

transfer capability (simultaneous TTC) values in performing SIL studies “provided that 

these TTCs are the values that are used in operating the transmission system and posting 

availability on OASIS.”189 The Commission requires sellers to provide evidence that 

simultaneous TTC values account for simultaneity, internal and first-tier external 

transmission limitations, and transmission reliability margins.190

150. In the NOPR, the Commission proposed to clarify several issues about how to 

perform SIL studies and the associated Submittals 1 and 2 found on the Commission’s 

website.191 In particular, the Commission proposed to clarify issues relating to what is 

included in OASIS practices, how to deal with conflicts between OASIS practices and 

 

188 Id. P 152 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354); see 

also Puget, 135 FERC ¶ 61,254 at P 15 (“Long-term firm transmission reservations for 

applicant/affiliate generation resources that serve study area load reduce the amount of 

study are transmission capability available to potential competitors.”).

189 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 155 (quoting Order No. 697, FERC 

Stats. & Regs. ¶ 31,252 at P 364).

190 Id.; see also Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 142 

(clarifying that “the use of simultaneous TTC values in the SIL study must properly 

account for all firm transmission reservations, transmission reliability margin, and 

capacity benefit margin.”).

191 The sample spreadsheets for Submittals 1 and 2 are found at the Commission’s 

website at http://www.ferc.gov/industries/electric/gen-info/mbr/authorization.asp under 

“Quick Links.”
Docket No. RM14-14-000 93

the Commission directions provided in Appendix B of Puget, and the correct load value 

to use in the SIL study.

151. The Commission stated that the purpose of the SIL study is to calculate the total 

simultaneous import capability available to first-tier uncommitted generation resources, 

while also considering system limitations and existing resource commitments (i.e., longterm firm transmission reservations).192

 Therefore, the methodology a transmission 

provider uses to calculate simultaneous TTC values193 must be consistent with the 

methodology it uses for calculating and posting available transfer capability (ATC)194

and for evaluating firm transmission service requests, consistent with Commission 

policy and precedent.195 The Commission stated that import capability available to a 

transmission provider during real-time operations should not be included in the 

transmission provider’s SIL value if such transmission import capability is not available 

to non-affiliated uncommitted generation resources requesting long-term firm 

transmission service.196

 

192 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 158.

193 See row 4 of proposed Submittal 1 (Total Simultaneous Transfer Capability).

194 In the NOPR, FERC Stats. & Regs. ¶ 32,702 at P 25, ATC was inadvertently 

defined as “available transmission capability”; it should have been “available transfer 

capability.” See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 57. 

195 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 158.

196 Id.
Docket No. RM14-14-000 94

a. OASIS Practices

i. Commission Proposal

152. In the NOPR, the Commission proposed to clarify that the term “OASIS 

practices” refers specifically to the seasonal benchmark power flow case modeling 

assumptions, study solution criteria,197 and operating practices historically used by the 

first-tier and study area transmission providers198 to calculate and post ATC and to 

evaluate requests for firm transmission service.199

153. The Commission also proposed to clarify that in performing a SIL study, the 

transmission provider must utilize its OASIS practices consistent with the administration 

of its tariff. The seasonal benchmark power flow cases submitted with a SIL study 

should represent historical operating practices only to the extent that such practices are 

available to customers requesting firm transmission service. For example, if the 

transmission provider does not allow the use of an operating guide when evaluating firm 

 

197 Study solution criteria may include but are not limited to distribution factor 

thresholds, transformer tap adjustments, reactive power limits, transmission equipment 

ratings, and model solution settings. Id. P 159 n.169.

198 We reiterate that, while entities may not be familiar with all of the OASIS 

practices of transmission providers in first-tier balancing authority areas, they should at 

least be familiar with major constraints, path limits, and delivery problems in neighboring 

transmission systems. Id. P 159 n.170 (citing Order No. 697, FERC Stats. & Regs 

¶ 31,252 at P 354 n.361).

199 The interruptible nature of non-firm transmission service makes using these 

practices an inappropriate means of calculating the study area’s SIL value. Id. P 161 

n.171.
Docket No. RM14-14-000 95

transmission service requests, the transmission provider should not use the operating 

guide when calculating SIL values.200

ii. Commission Determination

154. There were no comments on the above proposals. Therefore, we adopt the 

proposals as set forth in the NOPR to clarify that the term “OASIS practices” refers 

specifically to the seasonal benchmark power flow case modeling assumptions, study 

solution criteria, and operating practices historically used by the first-tier and study area 

transmission providers to calculate and post ATC and to evaluate requests for firm 

transmission service, and to clarify that in performing a SIL study, the transmission 

provider must utilize its OASIS practices consistent with the administration of its tariff. 

We believe these clarifications will improve consistency between the methodology a 

transmission provider uses to calculate SIL values and the methodology it uses for 

calculating and posting ATC and for evaluating transmission service requests.

 

200 By “operating guide” we generally refer to the North American Electric 

Reliability Corp. (NERC)-defined term “Operating Procedure,” which is defined as “a

document that identifies specific steps or tasks that should be taken by one or more 

specific operating positions to achieve specific operating goal(s).” See NERC, Glossary 

of Terms Used in NERC Reliability Standards 53 (2014),

http://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf. In 

the SIL study context, this may include switching procedures, special protection systems, 

load throw-over schemes, temporary transmission line rating changes, and other actions 

that are not typically represented in the seasonal benchmark power flow models. NOPR, 

FERC Stats. & Regs. ¶ 32,702 at P 161 n.172.
Docket No. RM14-14-000 96

b. SIL Studies and OASIS Practices

i. Conflicts Between OASIS Practices and Puget

(a) Commission Proposal

155. In the NOPR, the Commission proposed several clarifications for instances when 

the methodology a transmission provider uses to calculate SIL values is inconsistent 

with the methodology the transmission provider uses for calculating and posting ATC 

and for evaluating transmission service requests. The Commission proposed to clarify 

that where there is a conflict between OASIS practices and the Commission directions 

provided in Appendix B of Puget, sellers should follow OASIS practices except as noted 

in the NOPR. The Commission reminded sellers that, in instances where actual OASIS 

practices differ from the SIL direction provided in Puget, sellers should use actual 

OASIS practices and provide documentation specifically identifying such practices.201 

The Commission also proposed to clarify that, to the extent that a seller’s SIL study 

departs from actual OASIS practices,202 such departures are only permitted where use of 

actual OASIS practices is incompatible with an analysis of import capability from an 

aggregated first-tier area.

203

 The Commission invited comments identifying potential 

 

201 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 162 n.173 (citing Order No. 697, 

FERC Stats. & Regs. ¶ 31,252 at P 356).

202 See Puget, 135 FERC ¶ 61,254 at app. B.

203 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 162.
Docket No. RM14-14-000 97

areas where actual OASIS practices may be incompatible with the performance of SIL 

studies.

156. The Commission also reminded sellers that the calculated SIL value should 

account for any limits defined in the tariff, such as stability or voltage.204 For example, 

if a seller utilizes a direct current analysis when performing a SIL study, but an 

alternating current analysis when evaluating transmission service requests, the seller 

must validate the total aggregate transfer level value, consistent with the transmission 

provider’s OASIS practices, if modeled using an alternating current load flow model.205

157. The Commission also reiterated that sellers may use a load shift methodology to 

perform a SIL study if they use a load shift methodology in their OASIS practices, 

“provided they submit adequate support and justification for the scaling factor used in 

their load shift methodology and how the resulting SIL number compares had the 

company used a generation shift methodology.”206

 

204 Id. P 163 n.175 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 346).

205 Id. P 163 n.176 (citing Pinnacle West Capital Corporation, 117 FERC 

¶ 61,316, at P 11 n.19 (2006) (“The resulting loading and voltages for the limiting cases, 

if derived from DC (direct current) load flow analysis would have been verified by AC 

(alternating current) load flow analysis and demonstrated to be within the applicable 

system operating limits as dictated by thermal, voltage or stability considerations to 

ensure system reliability. The Commission requires that such comparisons be included in 

the applicant’s working papers that are submitted to the Commission.”).

206 Id. P 164 n.177 (quoting Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at 

P 145). 
Docket No. RM14-14-000 98

158. Regarding accounting for long-term firm transmission reservations for generation 

resources that serve study area load, the Commission proposed to clarify that sellers 

must reduce the simultaneous TTC value207 by subtracting all long-term firm import 

transmission reservations, including reservations held by non-affiliated sellers.208 The 

Commission noted that it has already provided guidance with respect to accounting for 

long-term firm transmission reservations into the study area from affiliated generation 

resources located outside the study area.209 The Commission stated that proposed 

revised Appendix A Standard Screen Format accounts for all long-term firm import 

transmission reservations into the study area.210 The Commission also proposed 

revisions to Submittal 2 to account for these non-affiliate long-term firm transmission 

reservations to ensure that the determination of the SIL value is consistent with the 

method used to allocate this value to uncommitted generation capacity in the aggregated 

first-tier area for the indicative screens.211 

 

207 The revised Standard Screen Format (e.g., rows B1 and M1 in the market share 

screen (Long-Term Firm Purchases (from outside the study area))) must reflect the longterm firm reservations from Submittal 1, Table 1, row 5 of Puget. Puget, 135 FERC 

¶ 61,254 at app. B.

208 See NOPR, FERC Stats. & Regs. ¶ 32,702 at P 165 n.179 (citing revised app. 

E, Submittal 1, row 5).

209 Id. P 165 n.180 (citing Puget, 135 FERC ¶ 61,254 at P 15).

210 Id. P 165 & n.182 (citing to revised app. A, Standard Screen Format, 

specifically rows A1, B1, E1 and F1 in the market share screen and rows A1, B1, L1, and 

M1 in the pivotal supplier screen). 

211 Id. P 165.
Docket No. RM14-14-000 99

(b) Comments

159. Solomon/Arenchild agree with the Commission’s proposal to continue the 

requirement that SIL studies follow OASIS practices. Southeast Transmission Owners, 

however, state they are concerned that the Commission’s proposal to require sellers to 

“subtract all long-term firm import transmission reservations, including reservations 

held by non-affiliated sellers, from the simultaneous TTC value” could yield a 

misleading conclusion regarding market activity within a given area. According to 

Southeast Transmission Owners, the possession by a non-affiliate of a long-term 

transmission reservation across a seller’s interface that sinks in the seller’s home 

balancing authority area is an indicator of an open market, representing a decision by a 

competitor and the ability of that competitor to compete for load in the particular 

balancing authority area. Southeast Transmission Owners assert that, while the 

components of the screen inclusive of the SIL may yield a mathematically accurate 

result, the tabular depiction of the availability of transmission capacity for use by nonaffiliates, as proposed in the NOPR, becomes complicated and misleading and results in 

the market appearing more constrained than it really is. Southeast Transmission Owners 

urge the Commission to forego adoption of this proposal and not require deduction of 

long-term reservations held by non-affiliates of the seller. Instead, Southeast 

Transmission Owners ask that the Commission adopt an approach that appropriately 

reflects marketplace activity and the availability of transmission capacity to nonaffiliates. However, if the Commission proceeds with this proposal, then Southeast 

Transmission Owners urge that the Commission recognize the ability of sellers, when 
Docket No. RM14-14-000 100

performing a SIL study and the associated screens, to rebut the results through 

companion sensitivities and other data that show how the utilization of import capability 

by non-affiliates is indicative of a competitive marketplace.212 

(c) Commission Determination

160. We clarify that, where there is a conflict between the transmission provider’s 

tariff or OASIS practices and the Commission directions specified in Puget for 

performing SIL studies, sellers, except as noted below, should follow OASIS practices 

and provide documentation specifically identifying such practices.213 

161. We adopt the proposal that, to the extent that a seller’s SIL study departs from 

actual OASIS practices, such departures are only permitted where use of actual OASIS 

practices is incompatible with an analysis of import capability from an aggregated firsttier area. The calculated SIL value should account for any limits defined in the tariff, 

such as stability and voltage.214 Sellers may use a load shift methodology to perform a 

SIL study if they use a load shift methodology in their OASIS practices, provided they 

submit adequate support and justification for the scaling factor used in their load shift 

 

212 Duke Energy Carolinas, LLC, Duke Energy Progress, Inc., Louisville Gas and 

Electric Co., Kentucky Utilities Co., South Carolina Electric and Gas Co., and Southern 

Companies Services, Inc., acting as agent for Alabama Power Co., Georgia Power Co., 

Gulf Power Co., and Mississippi Power Co. (Southern Companies) (collectively, 

Southeast Transmission Owners) at 3.

213 See Order No. 697, FERC States. & Regs. ¶ 31,252 at P 356.

214 Id. P 346.
Docket No. RM14-14-000 101

methodology and show how the resulting SIL values compare to those that would be 

obtained if the seller used a generation shift methodology.215 

162. We also adopt the proposal to direct sellers to subtract all long-term firm import 

transmission reservations (including those held by non-affiliated sellers) from the 

simultaneous TTC and historical peak load values. Finally, we adopt the proposed 

revisions to Submittal 2 to account for these non-affiliate long-term firm transmission 

reservations. We note that the adopted Submittals 1 and 2 spreadsheet has an additional 

row in Submittal 2 for each non-affiliated long-term firm transmission reservation to 

more clearly illustrate that each transaction should be reported separately. There is also 

an additional row in the adopted spreadsheet in Submittal 2 for each power purchase 

agreement for the same reason.216

163. In response to Southeast Transmission Owners, we find that reducing the 

simultaneous TTC value and historical peak load value by long-term firm transmission

reservations held by both affiliates and non-affiliates properly accounts for all import 

capability used to serve affiliated and non-affiliated load in the study area. This 

provides an accurate measure of the study area’s load and import capability that is not 

 

215 Order No. 697-A, FERC States. & Regs. ¶ 31,268 at P 145.

216 Though the spreadsheet published in the NOPR did not contain these additional 

rows, the original instructions for Submittal 2 published in Appendix B of Puget and the 

proposed spreadsheet posted on the Commission’s website each had the instruction to 

insert “as many rows as necessary” to report each power purchase agreement. Finally, 

the descriptive text in rows 2 and 6 of Submittal 2 has been changed to “Power Purchase 

Agreement” instead of “Purchased Power Agreement” to be consistent with this 

nomenclature as used elsewhere in this Final Rule.
Docket No. RM14-14-000 102

available to uncommitted generation capacity in the first-tier area. We note that such 

reservations are properly accounted for in the indicative screens and that treating all 

long-term firm transmission reservations in a consistent manner should reduce confusion 

rather than increase it. With respect to Southeast Transmission Owners’ request that the 

Commission recognize the ability of sellers to rebut SIL study results through 

companion sensitivities, we note that sellers “[m]ay submit additional sensitivity studies, 

including a more thorough import study as part of the DPT. We reaffirm, however, that 

any such sensitivity studies must be filed in addition to, and not in lieu of, a SIL 

study.”217 

ii. Wheel-Through Transactions

(a) Commission Proposal

164. The Commission proposed to clarify that sellers must account for wheel-through 

transactions where such transactions are used to serve a non-affiliated load that is 

embedded within a study area. Specifically, the Commission proposed that the seller 

reduce the simultaneous TTC value by subtracting the value of all wheel-through 

transactions. The Commission observed that while wheel-through transactions are not 

used to serve study area load, they reduce the amount of transmission capability 

available to first-tier generators competing to serve study area load. Thus, the 

Commission proposed that these transactions be accounted for as long-term firm import 

 

217 Order No. 697-A, FERC States. & Regs. ¶ 31,268 at P 146.
Docket No. RM14-14-000 103

transmission reservations and reported in Submittal 2 and proposed corresponding 

changes to Submittal 2. 

(b) Comments

165. Solomon/Arenchild state they do not understand the rationale and intent of the 

proposal to include wheel-through transactions as a deduction to the amount of 

transmission capability available to first-tier generators to serve study area load. 

According to Solomon/Arenchild, wheel-through reservations generally do not reduce 

overall import capability because the import schedule nets out against the subsequent 

export schedule and that such reservations are not used to serve load in the balancing 

authority area. Southeast Transmission Owners voice similar concerns about the 

Commission’s proposal regarding wheel through transactions.218 According to 

Southeast Transmission Owners, this proposal results in an inequitable reduction of a 

seller’s SIL that is not indicative of actual marketplace activity. Further, Southeast 

Transmission Owners state that, in their experience, transmission operators use the term 

wheel through transaction to describe transactions that are imported into, and then 

exported out of, their particular areas of operation, thereby not serving load in that study 

area. Southeast Transmission Owners are unclear what transactions the NOPR would 

purport to capture by this new requirement and whether a wheel through transaction 

under the NOPR must in fact be supported by a long-term firm reservation.

 

218 Southeast Transmission Owners at 4 (citing NOPR, FERC Stats. & Regs. 

¶ 32,702 at P 166).
Docket No. RM14-14-000 104

166. Southeast Transmission Owners are concerned that the proposal may cause 

confusion among sellers, result in the capture of transactions that are beyond the 

intended scope, and contribute to less reliable SIL values. Given these concerns over the 

Commission’s proposal, Southeast Transmission Owners request that the Commission 

(1) clarify or elaborate what it means by wheel through transactions sinking in the 

seller’s area, and (2) limit this new requirement to this category of transactions that are 

supported by long-term firm reservations held by the seller and its affiliates. 

(c) Commission Determination

167. We agree with commenters’ interpretation of the term wheel-through to mean 

long-term firm transmission reservations that enter and exit a study area, but do not 

serve load in that study area. While a wheel-through transaction is still considered to be 

reserved capability on transmission lines similar to other long-term firm transmission 

reservations, a traditional wheel-through does not serve a study area’s Historical Peak 

Load and, as such, should not be recognized as a long-term firm transmission 

reservation for the purposes of the SIL study. Accordingly, we clarify that the NOPR 

should have instead used the terminology “wheel-into,” which refers to a long-term firm 

transmission reservation that enters a study area and serves non-affiliated load 

embedded in that study area. Thus, we make this distinction to clarify these terms in the 

Final Rule, and to adopt the NOPR proposal to apply to wheel-into transactions rather 

than to wheel-through transactions. 

168. Further, we clarify that wheel-into or other similarly related import transactions 

supported by first-tier, long-term firm transmission reservations used to serve non-
Docket No. RM14-14-000 105

affiliated load embedded within the study area are to be accounted for in a consistent 

manner, and the seller should reduce the simultaneous TTC value and historical peak 

load value by subtracting the value of all these transactions.219 

169. Additionally, while import and export transactions may net out for the purpose of 

calculating net area interchange, the Commission does not net out such long-term firm 

transmission reservations that are used to serve non-affiliated load embedded within the 

study area. Finally, we refine our proposed language in row 3 and row 7 in Submittal 2 

to remove any potential confusion with the use of the term “wheel-through” to read, 

“Transaction to serve non-affiliated, load embedded in the study area using external 

generation.” 

iii. Preferred Approach for Treating Controllable Tie 

Lines

(a) Proposal

170. The Commission proposed to clarify that, where a first-tier market or balancing 

authority area is directly interconnected to the study area only by controllable tie lines220

and is not interconnected to any other first-tier market or balancing authority area, 

 

219 In Submittal 1, Long-Term Firm Transmission Reservations (row 5) are 

deducted from Total Simultaneous Transfer Capability (row 4) to yield the Calculated 

SIL Value (row 6). The Calculated SIL Value is compared to Adjusted Historical Peak 

Load (row 8) and Uncommitted First-Tier Generation (row 9) to determine the SIL Study 

Value (row 10), which is limited by those two values.

220 Controllable tie lines include direct current (DC) transmission facilities and 

alternating current (AC) transmission facilities with the ability to control the magnitude 

and direction of power flows through equipment such as converters, phase shifting 

transformers, variable frequency transformers, etc.
Docket No. RM14-14-000 106

sellers should follow their OASIS practices regarding calculation and posting of ATC 

for such areas. If sellers’ OASIS practices are incompatible with the SIL study (e.g.,

ATC is based on tie line rating), sellers may use an alternative process to account for 

import capability for such tie lines.221 The Commission also proposed to clarify that, in 

such circumstances, it will be presumed reasonable to model a controllable tie line as a 

single equivalent first-tier generator connected to the study area by a radial line. The 

Commission stated that sellers should document any instances where modeling of 

controllable tie lines deviates from OASIS practices, and explain such deviations, 

including: how tie line flow is accounted for in the net area interchange calculations; 

how tie line flow is scaled or otherwise controlled when calculating simultaneous 

incremental transfer capability; and how long-term firm transmission reservations are 

accounted for over controllable tie lines.222

(b) Comments

171. Solomon/Arenchild seek clarification of the preferred approach for treating 

controllable tie lines. According to Solomon/Arenchild, there are two reasonable 

options for treating such lines with regard to the Commission’s proposal that SIL studies 

 

221 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 167.

222 Id.
Docket No. RM14-14-000 107

for markets “directly connected to the study area [first-tier] only by controllable tie 

lines” should follow OASIS practices regarding calculation and posting of ATC.223 

Using a market that has an high-voltage direct current (HVDC) tie of 200 MW as an 

example, Solomon/Arenchild state that one option for treating such lines is that the SIL 

study could include a 200 MW generator inside the balancing authority area being 

analyzed, assigning any share of the generation to the holder of long-term reservations 

on the HVDC tie, if any. Another option is that the SIL study could treat the HVDC tie 

as a 200 MW generator outside of the balancing authority area being analyzed but 

include it as part of the aggregated generation in the first-tier area.

(c) Commission Determination

172. We clarify that, for purposes of performing market power studies for marketbased rate authorization, where a first-tier market or balancing authority area is directly 

interconnected to the study area only by controllable tie lines and is not interconnected to 

any other first-tier market or balancing authority area, sellers should follow their OASIS 

practices for calculation and posting of ATC for such areas.224 However, if a seller’s 

OASIS practices are incompatible with the SIL study (e.g., ATC is based on tie line 

 

223 Solomon/Arenchild at 12 (quoting NOPR, FERC Stats. & Regs. ¶ 32,702 at 

P 167).

224 Controllable tie lines are transmission facilities with associated equipment 

enabling control of the magnitude and direction of power flows over the facility. One 

example of a controllable tie line is the Cross Sound Cable, which connects the New 

England and New York markets. 
Docket No. RM14-14-000 108

rating), the seller may use an alternative process to account for import capability for such 

tie lines. 

173. In such circumstances where a seller’s OASIS practices are incompatible with the 

SIL study, sellers shall not model a controllable tie line as a radial line connected to an 

equivalent study area generator, as proposed by Solomon/Arenchild, as this leads to 

potential SIL study errors when scaling generation. However, for purposes of calculating 

the SIL value and consistent with the NOPR proposal, where a first-tier market or 

balancing authority area is directly interconnected to the study area only by controllable 

tie lines, each controllable tie line shall be modeled as a radial line connecting the study 

area to a first-tier area generator located in the first-tier area, and may be scaled as firsttier area generation. For the purposes of allocating SIL values to aggregate uncommitted 

first-tier generation capacity, sellers must consider actual uncommitted generation 

capacity in each first-tier area, rather than the capability of the controllable tie line. 

iv. Treatment of Controllable Merchant Lines

(a) Commission Proposal

174. The Commission stated that in the NOPR that, to the extent that the study area is 

directly interconnected to first-tier areas by controllable merchant transmission lines 

(e.g., Linden VFT), sellers should properly account for capacity rights on such lines. If 

sellers hold long-term capacity rights on such lines, these rights should be accounted for 

as long-term firm transmission reservations. If sellers lack sufficient knowledge 

regarding the existence and attributes of capacity rights on controllable merchant lines, 
Docket No. RM14-14-000 109

sellers shall assume the full capacity of such lines is held by sellers with long-term firm 

transmission reservations.225

(b) Comments

175. Solomon/Arenchild note their confusion as to controllable merchant lines and the 

Commission’s statement that, “[i]f sellers lack sufficient knowledge regarding the 

existence and attributes of capacity rights on controllable merchant lines, they shall 

assume the full capacity of such lines is held by sellers with long-term firm transmission 

reservations.”226 Solomon/Arenchild ask why these long-term firm transmission rights 

should be treated any differently than any other transmission reservations. Additionally, 

they ask whether the reference to “sellers” with long-term firm transmission rights really 

is a reference to transmission right holders as opposed to the “sellers” filing the screens. 

Further, Solomon/Arenchild seek clarification that the Commission’s intent is to reflect 

the full amount of the controllable merchant line capacity in determining the total size of 

the market.227

(c) Commission Determination

176. We clarify in response to the question asked by Solomon/Arenchild that the 

reference to “sellers” was intended to be a generic reference to transmission right holders 

and not to apply to the seller submitting the study.

 

225 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 168.

226 Solomon/Arenchild at 12; NOPR, FERC Stats. & Regs. ¶ 32,702 at P 168. 

227 Solomon/Arenchild at 12-13.
Docket No. RM14-14-000 110

177. SIL values are net of long-term firm transmission reservation. We find that 

capacity rights on controllable merchant lines are comparable to long-term firm 

transmission reservations and should be deducted from the Total Simultaneous Transfer 

Capability value and Historical Peak Load value. Capacity rights on controllable 

merchant lines represent import capability that is only available to a specific transmission 

customer pursuant to the Commission’s policies for merchant transmission, and is 

therefore not generally available to any uncommitted generator in the first-tier area. In 

the past, some sellers have treated controllable merchant transmission lines as if such 

lines were available to import generation into the study area. Such treatment is 

inconsistent with the merchant transmission model. However, sellers should be able to 

determine whether merchant transmission lines are subscribed given the requirement that 

merchant transmission developers disclose the results of their capacity allocation 

process.

228

 However, where the seller is unaware of the terms and conditions for thirdparty capacity rights on controllable merchant lines, the seller must make a conservative 

assumption and subtract from the Total Simultaneous Transfer Capability and Historical 

Peak Load values the full capacity of the controllable merchant line as a long-term firm 

transmission reservation. We find this to be a reasonable assumption as the capacity on 

 

228 See Allocation of Capacity on New Merchant Transmission Projects and New 

Cost-Based, Participant-Funded Transmission Projects Priority Rights to New 

Participant-Funded Transmission, 142 FERC ¶ 61,038 (2013).
Docket No. RM14-14-000 111

controllable merchant lines typically is fully subscribed.

229

 This approach ensures that 

such capacity rights on controllable merchant transmission lines are treated in a 

comparable manner to long-term firm transmission reservations. 

v. Inclusion of All Load Data 

(a) Commission Proposal

178. In the NOPR, the Commission proposed to require sellers to include all load 

associated with balancing authority area(s) within the study area. The Commission 

stated that the SIL study is “intended to provide a reasonable simulation of historical 

conditions” and is not “a theoretical maximum import capability or best import case 

scenario.”230 The Commission noted that the SIL study “is a study to determine how 

much competitive supply from remote resources can serve load in the study area.”231 In 

the NOPR, the Commission noted the clarification in Puget that sellers should not report 

study area non-affiliated load as study area native load, and should adjust modeled net 

area interchange by the same amount.232 The Commission stated that the exclusion of 

all study area non-affiliated load may result in SIL values that are inconsistent with the 

intent of the indicative screens. Furthermore, in the event the SIL value is limited by 

 

229 This assumes that the capacity of the merchant tie line is included in the net 

area interchange value as well, such that the net impact on the SIL value is zero.

230 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 169 (quoting Order No. 697, FERC 

Stats. & Regs. ¶ 31,252 at P 354).

231 Id. (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 361). 

232 Id. (citing Puget, 135 FERC ¶ 61,254 at app. B).
Docket No. RM14-14-000 112

study area load, restricting study area load to affiliated load fails to account for import 

capability that may be used to serve wholesale load customers. The Commission stated 

that sellers should only adjust the reported value for modeled net area interchange to 

account for first-tier generation serving load associated with a first-tier balancing 

authority area that is modeled as part of the study area.

233

 To ensure Submittal 1 is 

consistent with these requirements, the Commission proposed to revise row 8 to read 

“Adjusted Historical Peak Load” (instead of “Study area adjusted native load”).

(b) Comments

179. Solomon/Arenchild and Southeast Transmission Owners agree with the 

Commission’s proposal that sellers include in SIL studies all load associated with 

balancing authority area(s) within the study area, with sellers’ specific load obligations 

accounted for in the indicative screen analysis. However, Idaho Power contends that the 

Commission’s proposal prevents an accurate accounting for a fraction of non-affiliate 

load that is served by non-affiliate generation when both are located in the study area. 

Further, Idaho Power argues that the proposal to include both affiliate and all nonaffiliate load in the definition of Historical Peak Load means that any remaining amount 

of non-affiliate load not served by non-affiliate generation in the study area would be 

included in long-term firm transmission reservations, which would reduce the 

 

233 Id. (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 169 n.186 (“If the 

load is modeled as part of another area, i.e., as a non-area load attached to an area bus, 

and the net area interchange calculation includes both tie lines and non-area loads 

attached to area buses, net area interchange associated with service to such load should be 

approximately zero, and no adjustment will be necessary.”)).
Docket No. RM14-14-000 113

simultaneous TTC value by this fraction of non-affiliate load. According to Idaho 

Power, this would lead to the fraction of the non-affiliate load served by internal nonaffiliate generation incorrectly appearing as affiliate load.

234

(c) Commission Determination

180. We adopt the proposal to require sellers to include in the SIL studies all load 

associated with balancing authority area(s) within the study area. With regard to Idaho 

Power’s argument regarding consideration of study area non-affiliate load served by 

non-affiliate generation, we first note that study area non-affiliate load not served by 

study area non-affiliate generation would only appear as a long-term firm transmission 

reservation when served by first-tier generation capacity. Furthermore, as the 

Commission noted in the NOPR, Adjusted Historical Peak Load includes both affiliate 

and non-affiliate native load, as well as wholesale load. This ensures the SIL value, 

when limited by Adjusted Historical Peak Load, remains consistent with the load values 

in the indicative screens and also does not provide biased SIL values when they are 

limited by load. This clarification is not intended to re-categorize study area nonaffiliated load as study area affiliate load, but rather clarify that they together are 

available to be served by competitors in the first-tier market and from available nonaffiliate generators within the study area. However, we agree with Idaho Power that

non-affiliate load served by internal non-affiliate generation with a firm commitment 

should not be represented as being available to be served by competitors. Therefore, we 

 

234 Idaho Power at 4-5.
Docket No. RM14-14-000 114

clarify that when a non-affiliate generator has a firm commitment to serve a non-affiliate 

load and both are located within the study area, then this non-affiliate generator should 

not be scaled and the value of this non-affiliate load should not be included in the study 

area Historical Peak Load as reported on row 7 of Submittal 1. 

vi. Sources of Load Data

(a) Commission Proposal

181. The Commission stated in the NOPR that it is also looking for consistent, 

reported load values for all sellers to use in preparing SIL studies, noting that Puget

requires that sellers use FERC Form No. 714 load values or explain the source of the 

data used.235 The Commission noted that some sellers have stated that the load values in 

their models differ from FERC Form No. 714 data and have sought to rely on data from 

sources other than FERC Form No. 714. The Commission sought industry comment on 

what sources other than FERC Form No. 714 may be appropriate sources to rely on in 

determining historical peak load.

(b) Comments

182. Idaho Power believes that, with the other adjustments in the NOPR, use of FERC 

Form No. 714 data, which includes the balancing authority area load, is appropriate. 

However, Solomon/Arenchild state that, in their experience, the load included in 

seasonal benchmark power flow models often does not precisely match loads reported in 

 

235 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 170 (citing Puget, 135 FERC 

¶ 61,254 at app. B, Submittal 1, n.iv).
Docket No. RM14-14-000 115

FERC Form No. 714 and typically used in the indicative screens. Solomon/Arenchild 

recommend that the Commission allow sellers to use the load data underlying the 

transmission models for purposes of row 7 of Submittal 1.

183. Southeast Transmission Owners believe that, regardless of its source, the load 

data must incorporate all data in the market under study. Southeast Transmission 

Owners use Southern Companies as an example to demonstrate that FERC Form No. 

714 may not always reflect aggregated balancing authority area information necessary to 

determine the historical peak load for the SIL study because the FERC Form No. 714 

data reflects load data of the Southern Companies and not the load of all other loadserving entities operating inside the Southern Companies balancing authority area. 

Therefore, Southeast Transmission Owners argue that, in order to perform a SIL study 

consistent with the Commission’s existing requirements, entities like Southern 

Companies use archived load data from their energy management systems in order to 

provide the requisite balancing authority area information needed for the study. 

Southeast Transmission Owners assert that, while there may be other FERC Form 

No. 714 alternatives, archived energy management systems data serves as a reliable, 

cost-effective means for satisfying the Commission’s requirements and ensuring that the 

appropriate inputs to the SIL have been obtained in order to yield accurate results. 

(c) Commission Determination

184. We do not find it necessary for the load used in the seasonal benchmark case 

model to exactly match FERC Form No. 714 data. However, the Historical Peak Load 

reported in row 7 of Submittal 1 should be consistent with the load used in the seasonal 
Docket No. RM14-14-000 116

benchmark case model. We clarify that entities are permitted to deviate from reported 

FERC Form No. 714 load values where such values fail to account for all load within the 

study area, but sellers must explain and document their reasons for using an alternative 

data source and any adjustments made to the data. In addition, we find it acceptable for 

sellers to use energy management systems data to represent Historical Peak Load values, 

so long as sellers attest that such data is unmodified and accurate, and includes all study 

area affiliate and non-affiliate load.

vii. Submittals 1 and 2

(a) Commission Proposal

185. The Commission clarified in the NOPR that the values provided in Submittal 1 

should generally be supported by the submitted seasonal benchmark power flow 

models.236 In particular, the Commission explained that row 1 (Simultaneous 

Incremental Transfer Capability), row 2 (Modeled Net Area Interchange), and row 4 

(Total Simultaneous Transfer Capability) should agree with the corresponding values 

from the seasonal benchmark power flow models. Any differences should be explained 

by the seller. The Commission proposed to update Submittal 1, as reflected in Appendix 

E to the NOPR, to provide additional clarity on the expected values for certain rows.237 

As addressed above in the discussion of wheel-through transactions, the Commission also 

 

236 Id. P 171.

237 See Revised app. E, Submittal 1.
Docket No. RM14-14-000 117

proposed revisions to Submittal 2. Revised versions of Submittals 1 and 2 were posted 

on the Commission’s website. 

(b) Commission Determination

186. We adopt the proposal to clarify that the values provided in Submittal 1 should 

generally be supported by the submitted benchmark power flow models. Any 

differences should be explained by the seller. We will also adopt the proposal to update 

Submittal 1, as reflected in Appendix E of the NOPR, to provide additional clarity on 

the expected values for certain rows. We will post the revised versions of Submittals 1 

and 2 on the Commission’s website and direct sellers to begin using the revised versions 

no later than the effective date of this Final Rule. 

c. Simultaneous TTC Method

i. Commission Proposal

187. The Commission proposed in the NOPR to define the following standard 

guidance for data submittals and representations that sellers using the simultaneous TTC 

method must provide to the Commission. First, the Commission stated that sellers must 

provide historical data of actual, hourly, real-time TTC values used for operating the 

transmission system and posting transmission capacity availability on OASIS. Sellers 

should identify the date and hour from which simultaneous TTC values were calculated. 

Sellers may use the maximum sum of TTC values for any day and time during each 

season, so long as they also demonstrate that these TTC values are simultaneously 

feasible. Sellers may demonstrate that TTC values are simultaneously feasible by 

performing a power flow study that verifies that the declared simultaneous TTC value is 
Docket No. RM14-14-000 118

simultaneously feasible while accounting for all internal and external transmission 

limitations identified in Appendix E of the NOPR and Puget.

238

 Sellers may also 

provide expert testimony explaining how the specific criteria and procedures used to 

calculate posted TTC values result in TTC values that are simultaneously feasible.

188. The Commission reiterated that, in the event there are limited interconnections 

between first-tier markets, the Commission will review evidence that potential loop flow 

between first-tier areas is properly accounted for in the underlying SIL values on a caseby-case basis.239

 However, the Commission clarified that simply attesting that first-tier 

markets or balancing authority areas are not directly interconnected is not sufficient 

evidence that TTC values posted on OASIS are simultaneous, as this does not preclude 

internal transmission limitations from limiting the simultaneous TTC below the sum of 

individual path TTC values.

ii. Commission Determination

189. There were no comments addressing this proposal. Thus, we adopt the standard 

guidance for data submittals and representations that sellers using the simultaneous TTC 

method must provide to the Commission. 

 

238 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 172.

239 Id. P 173 (citing Atlantic Renewables Projects II, 135 FERC ¶ 61,227, at P 9 

(2011)).
Docket No. RM14-14-000 119

d. Other Issues

i. Comments

190. Solomon/Arenchild seek several clarifications relating to the determination of the 

SIL and its application in the indicative screens versus a DPT analysis. First, they state 

that the SIL value for the indicative screens is calculated for four seasonal peaks 

(Winter, Spring, Summer, and Fall), whereas the DPT analysis typically evaluates a 

“Shoulder” season that combines Spring and Fall. Solomon/Arenchild seek that the 

Commission clarify that the DPT analysis of a “Shoulder” season should use the average 

of the Spring and Fall values, unless it can be demonstrated that facts exist to support 

use of either Spring or Fall values alone for the Shoulder season. 

191. Second, Solomon/Arenchild state that, in their experience, the SIL values used in 

the DPT and those reported in the SIL submittals may legitimately differ as a direct 

result of underlying differences between the DPT and the indicative screens related to 

the treatment of long-term transmission reservations. Solomon/Arenchild ask that the 

Commission clarify that it is appropriate when calculating the SIL values used in the 

DPT analysis not to deduct any associated long-term transmission for a remote 

generating facility during a period when such generation is not fully available or not 

economic (or, alternatively, to increase the SIL to reflect additional import capacity). 

192. Finally, Solomon/Arenchild seek clarification of the definition of “long-term firm 

transmission contracts.” According to Solomon/Arenchild, the Commission’s current 

regulations define transmission contracts with a term of 28 days or more as “long-term” 

and direct that such contracts be reflected in the SIL analysis. However, 
Docket No. RM14-14-000 120

Solomon/Arenchild assert that such contracts may be excluded in the indicative screen 

analysis and/or the DPT because they do not meet the definition of “long-term” as being 

one year or longer, as used for analyzing energy markets. While they recognize that 

both the SILs and the indicative screens are intended to depict an accurate historical 

representation of markets, Solomon/Arenchild contend that including only transmission 

reservations with durations of one year or longer provides a more robust analysis. 

Accordingly, Solomon/Arenchild suggest that the Commission clarify that only longterm contracts, including seasonal contracts, that are one year or longer be included in 

both the SIL study and the indicative screen and/or DPT analyses.240

193. EEI states it is concerned with the volume of clarifications in the Commission’s 

proposal regarding SIL studies. EEI encourages the Commission to engage in further 

dialogue with the regulated community about the proposed changes, to ensure that the 

changes are reasonable, clear, accurate, and easy to implement. Additionally, EEI 

expresses concern that some of its members are already being required to make changes 

in their SIL analyses.241

194. Southeast Transmission Owners support EEI’s request for the Commission to 

further caucus with industry regarding SIL studies. Given the complexities underlying 

the market-based rate program and the fact that industry’s most recent round of triennial 

updated market power analysis filings will continue until June 2016, Southeast 

 

240 Solomon/Arenchild at 14-15.

241 EEI at 21.
Docket No. RM14-14-000 121

Transmission Owners state that the Commission does not need to rush action with 

regard to these proposals.242 Further, Southeast Transmission Owners are concerned that 

the Commission’s proposals may cause confusion among sellers, rather than the 

intended goal of streamlining the market-based rate program, and may result in less 

reliable SIL values.

195. SoCal Edison recommends that the Commission require each RTO/ISO, and the 

CAISO in particular, to perform a SIL study for common use.

ii. Commission Determination

196. We find Solomon/Arenchild’s request for clarification regarding which Spring and 

Fall SIL values to use for the DPT analysis to be beyond the scope of this rulemaking 

proceeding. We also find their request for clarification regarding calculation of the SIL 

values used in the DPT analysis to be beyond the scope of this rulemaking proceeding. 

197. Additionally, we decline Solomon/Arenchild’s request to redefine the applicable 

duration of long-term firm transmission reservations, currently defined as 28 days or 

longer, for purposes of the SIL study as this would inflate the amount of import capability 

available on a long-term basis. Solomon/Arenchild have not demonstrated why the 

Commission should change the definition for purposes of the SIL study. Indeed, the 

power flow cases utilized for SIL studies are a reflection of seasonal peaks such that a 

“monthly” designation for such reservations appropriately captures this designation. 

 

242 Southeast Transmission Owners at 6-7 (citing NOPR, FERC Stats. & Regs. 

¶ 32,702 at app. C).
Docket No. RM14-14-000 122

198. With regard to concerns about the volume and complexity of changes, we remind 

commenters that the proposed rule is primarily a clarification of existing policy and that 

the need for this clarification was based in part on a lack of specificity resulting in 

confusion with the SIL study process. To the extent sellers remain confused about any 

aspect of the Commission’s instructions regarding SIL studies, Commission staff will 

continue to be available to discuss these issues prior to an applicant submitting its filing.

199. In response to SoCal Edison’s request for the Commission to require each 

RTO/ISO to perform a SIL study for common use, the RTOs/ISOs do not have marketbased rate tariffs on file; thus, we will not require SIL studies from RTOs/ISOs. 

B. Vertical Market Power—Land Acquisition Reporting

1. Commission Proposal

200. In the NOPR, the Commission noted that all market-based rate sellers currently 

are required to provide, as part of their vertical market power analysis, a description of 

their ownership or control of, or affiliation with an entity that owns or controls, sites for 

generation capacity development243 and to file notices of change in status on a quarterly 

basis when they acquire sites for new generation capacity development.244 The 

Commission noted that in the more than six years since issuance of Order No. 697, not a 

single protest had been filed in response to disclosures regarding sites for new 

generation capacity development and it proposed to eliminate the requirement that

 

243 18 CFR 35.37(e)(2).

244 18 CFR 35.42(d).
Docket No. RM14-14-000 123

market-based rate sellers file quarterly land acquisition reports and provide information 

on sites for generation capacity development in market-based rate applications and 

triennial updated market power analyses (land acquisition reporting requirements)

because the burden of such reporting outweighs the benefits.245 The Commission noted

that, if there is a concern that a particular seller’s sites for generation capacity 

development may be creating a barrier to entry, the Commission can request additional 

information from the seller at any time.246

201. Thus, the Commission proposed to revise the regulations at 18 CFR 35.42 

relating to change in status reporting requirements to remove paragraph (d). This 

proposed revision would remove the requirement that sellers report the acquisition of 

control of a site or sites for new generation capacity development for which site control 

has been demonstrated. Likewise, the Commission proposed to revise the regulations at 

18 CFR 35.42 to remove paragraph (e), which pertains to the definition of site control 

for purposes of paragraph (d). In addition, the Commission proposed to revise 18 CFR 

35.42 at paragraph (b) to remove the reference to the reporting of acquisition of control 

 

245 For example, the Commission received, from the second quarter in 2012 to the 

fourth quarter in 2013, approximately 90 filings from 1,380 filers. This is a reporting 

burden on sellers and an inefficient use of Commission resources for information that has 

yet to produce an actionable item or elicit a single comment in almost five years. 

246 See Order No. 697-D, FERC Stats. & Regs. ¶ 31,305 at P 23 (“[I]f there is a 

concern that a particular seller may be acquiring land for the purpose of preventing new 

generation capacity from being developed on that land, the Commission can request 

additional information from the seller at any time.”).
Docket No. RM14-14-000 124

of a site or sites for new generation capacity development. The Commission also 

proposed to revise the market power analysis regulations at 18 CFR 35.37 to remove 

paragraph (e)(2), which requires sellers to provide information regarding sites for 

generation capacity development to demonstrate a lack of vertical market power. 

2. Comments

202. Several commenters support the Commission’s proposal to eliminate the land 

acquisition reporting requirements.247 These commenters contend that the reporting 

obligation is unnecessary and unduly burdensome, with little benefit, particularly given 

that in the last six years intervenors have not challenged whether sites for new generation 

capacity development created a barrier to entry.248 

203. EPSA and NRG Companies note that the purpose of the initial applications, 

triennial updates, and notices of change in status, is to identify for the Commission 

material facts and changes relevant to a seller’s qualification for market-based rate 

authority. EPSA and NRG Companies state that requirements that sellers file quarterly 

land acquisition reports fail to further the purpose of the triennial updates and notices of 

change in status filings.249 NRG Companies add that there is no reason to think that these 

reports would ever provide information that would call into question the validity of “the 

 

247 See, e.g., AEP at 5-7; E.ON at 7-8; EEI at 13; EPSA at 7; FirstEnergy at 9; 

NRG Companies at 7-8; NextEra at 10.

248 See E.ON at 7-8; EEI at 13; FirstEnergy at 9; NextEra at 10.

249 EPSA at 7; NRG Companies at 7-8.
Docket No. RM14-14-000 125

rebuttable presumption that sellers cannot erect barriers to entry with regard to the 

ownership or control of, or affiliation with any entity that owns or controls . . . sites for 

generation capacity development . . . .”250 As such, EPSA states that the Commission’s 

proposal furthers the Commission’s stated goal of reducing the regulatory burdens on 

market-based rate sellers.251

204. NextEra asserts that, in addition to being burdensome, the reports have limited 

value because the land acquisition reporting requirements do not allow the netting of 

generation in the interconnection queue when a market-based rate seller withdraws a 

proposed project from the interconnection queue or places a new project in-service. 

According to NextEra, as a result, the information on file with the Commission does not 

accurately reflect actual site control in the interconnection process and the quarterly 

reports provide little useful information to the Commission or the public.252

205. On the other hand, other commenters oppose removing the land acquisition 

reporting requirements.253 They argue that the fact that in the last six years intervenors 

have not challenged whether sites for new generation capacity development created a 

barrier to entry is not a reason for the Commission to ignore the issue in the future. AAI 

 

250 NRG Companies at 7-8 (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 

at P 446).

251 EPSA at 7.

252 NextEra at 10.

253 AAI at 10-12; APPA/NRECA at 26-27; TAPS at 2.
Docket No. RM14-14-000 126

argues that, due to the relative scarcity of land suitable for renewable energy 

development, incumbents can erect barriers to entry through strategic generation site 

acquisitions, i.e., accumulate renewable energy sites with the aim of preventing rivals 

from developing them. Further, AAI states that the composition of generation in the 

United States may be on the cusp of radical restructuring, pointing to state enacted 

Renewable Portfolio Standards and the United States Environmental Protection Agency’s 

rulemaking to reduce greenhouse gas emissions from new and existing power plants.254 

According to AAI, for the intended change in the generation fleet to occur, barriers to 

entry, including access to generation sites, must be minimized. AAI states that the 

Commission should continue to collect data on the acquisition of generation sites and 

recommends using a comprehensive database, as opposed to relying on complaints of 

affected parties, to monitor this issue in a systematic fashion. Lastly, AAI states that, 

given the anticipated high growth in renewable energy, revising land acquisition and 

generation capacity development reporting rules would be premature. 

206. Similarly, APPA/NRECA states that a number of economic, technological, and 

regulatory factors are inducing the retirement of substantial coal generation and the 

construction of substantial new gas-fired and renewable generation in the coming years. 

 

254 AAI at 11-12 (citing U.S. Energy Info. Admin., Most States Have Renewable 

Portfolio Standards, Feb. 3, 2012, available at

http://www.eia.gov/todayinenergy/detail.cfm?id=4850; Carbon Pollution Emission 

Guidelines for Existing Stationary Sources: Electric Utility Generating Units, 79 Fed. 

Reg. 34,830 (proposed June 18, 2014) (to be codified at 40 CFR pt. 60)).
Docket No. RM14-14-000 127

APPA/NRECA asserts that where this new generation will be located will be an 

important issue because most of the new generation will be location-constrained 

renewable resources. Further, APPA/NRECA asserts that, because of constraints on gas 

pipeline capacity, the location of gas-fired generation sites relative to existing and 

proposed gas pipelines is also critical. Lastly, APPA/NRECA asserts that the retirement 

of coal generation can change the economic and reliability factors that will determine 

where new generation may be located. APPA/NRECA warns that, because the location 

of new generation build-out may have important economic consequences, the 

Commission should not ignore the barriers to entry created by the acquisition of new 

generation sites.255 TAPS supports APPA/NRECA’s comments with respect to land 

acquisition reporting. TAPS opposes the proposed elimination of the land acquisition 

reporting requirement given the current dramatic changes in generation resource mixes, 

and in particular, the potential importance of access to gas pipeline facilities.256

3. Commission Determination

207. We adopt the NOPR proposal to eliminate the land acquisition reporting 

requirements. 

208. We continue to find that the current land acquisition reporting is of limited value 

in assessing barriers to entry. The existing land acquisition reports include: (1) the 

number of sites acquired; (2) the relevant geographic market in which the sites are 

 

255 APPA/NRECA at 26-27.

256 TAPS at 2.
Docket No. RM14-14-000 128

located; and (3) the maximum potential number of megawatts that are reasonably 

commercially feasible on the sites reported.257 Thus, the reports identify relevant 

geographic market/balancing authority areas, but such reports do not indicate specific 

locations or whether the sites are adjacent to the existing transmission grid or natural gas 

pipelines. Moreover, the reports do not include any metrics or analyses to indicate 

whether the seller’s land acquisitions provide it with control over a sufficient amount of 

sites to create a potential barrier to entry within a geographic market. 

209. As noted above, the land acquisition reporting requirements are burdensome for 

sellers and yield little, if any, offsetting benefit. Out of 58 filings of land acquisition 

reports from the fourth quarter in 2013 to the first quarter in 2015, none has been 

contested or has provided sellers and the Commission with useful information regarding 

barriers to entry.258 No one has used the information in a land acquisition report in a 

comment or protest challenging the market-based rate authority of any seller. 

210. In response to the concerns raised by AAI and APPA/NRECA, we clarify that 

intervenors are free to challenge an applicant’s claims that it has not erected barriers to 

entry. We also reiterate that the Commission retains the right to request additional 

information on such potential barriers to entry from the seller at any time if it has reason 

to believe that a seller’s acquisition of land has created a barrier to entry or otherwise 

 

257 18 CFR § 35.42(d).

258 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 89 n.109.
Docket No. RM14-14-000 129

been used to exercise vertical market power.259 Furthermore, the Commission will 

continue to require market-based rate sellers to affirmatively state that they and their 

affiliates have not and will not raise any barriers to entry in the relevant market, 

including of land acquisitions, as part of the Commission’s vertical market power 

analysis required in initial applications, triennials, and notices of change in status that 

affect the vertical market power analysis.

211. Finally, AAI suggests that the Commission utilize a comprehensive database to 

monitor the acquisition of generation sites in a systematic fashion. However, the 

Commission did not propose any refinements to the information collected in land 

acquisition reports but rather the elimination of the requirement. The comprehensive 

database recommended by AAI would be a major undertaking with uncertain benefits, for 

the reasons stated above, and is beyond the scope of this rulemaking. For these reasons, 

we reject this request.

212. We adopt the NOPR proposal to revise the regulations at 18 CFR 35.42 relating 

to the change in status reporting requirements to remove paragraph (d), the requirement 

that sellers report the acquisition of control of a site or sites for new generation capacity 

development for which site control has been demonstrated. We will also remove 

paragraph (e), which pertains to the definition of site control for purposes of paragraph 

 

259 See Order No. 697-D, FERC Stats. & Regs. ¶ 31,305 at P 23 (“[I]f there is a 

concern that a particular seller may be acquiring land for the purpose of preventing new 

generation capacity from being developed on that land, the Commission can request 

additional information from the seller at any time.”).
Docket No. RM14-14-000 130

(d), and revise paragraph (b) to remove the reference to the reporting of acquisition of 

control of a site or sites for new generation capacity development. Further, we adopt the 

NOPR proposal to revise the market power analysis regulations at 18 CFR 35.37 to 

remove paragraph (e)(2), which requires sellers to provide information regarding sites for 

generation capacity development to demonstrate a lack of vertical market power. 

C. Notices of Change in Status

1. Geographic Focus

a. Commission Proposal

213. In Order No. 697-A, the Commission clarified that sellers must report a change in 

status when they acquire 100 MW or more in the “geographic market that was the 

subject of the horizontal market power analysis on which the Commission relied in 

granting the seller market-based rate authority.”260 In the NOPR, the Commission 

proposed to clarify that the 100 MW reporting threshold in section 35.42(a)(1) is not 

limited only to markets previously studied. The Commission proposed that, if a seller 

acquires generation that would cause a cumulative net increase of 100 MW or more in 

any relevant geographic market (including generation in both the relevant geographic 

market itself and any first-tier/interconnected market with the potential to import into 

that market) since the seller’s most recent triennial updated market power analysis or 

change in status filing, the seller must make a change in status filing. This would 

include cumulative increases of 100 MW or more in a new market that has not 

 

260 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 512.
Docket No. RM14-14-000 131

previously been studied because, once the seller has generation in that market, it is a 

relevant geographic market for that seller. The Commission clarified that a net increase 

measures the difference between increases and decreases in affiliated generation. 

214. In Order No. 697-A, the Commission also provided the following example, “if a 

seller has a net increase of 50 MW in the geographic market on which the Commission 

relied in granting the seller market-based rate authority and 50 MW increase in a 

different geographic market that is in the same region . . . , the 100 MW or more 

threshold would not be met because the increase in generation capacity is less than [100] 

MW in each generation market and, accordingly, a change in status filing would not be 

required.”261 In the NOPR, the Commission clarified that this example described a 

situation where the geographic market on which the Commission relied in granting 

market-based rate authority was not first-tier to the geographic market in which the 

seller acquired an additional 50 MW. Thus, the Commission proposed to clarify that the 

100 MW threshold applies to the cumulative capacity added in any relevant geographic 

market, including what can be imported from first-tier markets, but does not cover 

situations where a seller acquires less than 100 MW in one market and less than 100 

MW in another market, as long as those two markets are not first-tier to each other. 

215. The Commission further proposed to require that the 100 MW threshold 

requirement for change in status filings be calculated based on a generator’s nameplate 

 

261 Id.
Docket No. RM14-14-000 132

capacity rating because it is a single value, it exists for all types of generators, it is 

generally a more conservative value than a seasonal or five-year average rating would 

be, and it allows for uniform measurements across different types of generators.

216. The Commission proposed to revise the regulatory text in section 35.42(a)(1) of 

the Commission’s regulations to provide greater clarity and direction on this topic.

b. Comments

217. Several commenters object to the Commission’s proposal to consider cumulative 

net increases of 100 MW or more of nameplate capacity in any relevant geographic 

market as well as any first-tier/interconnected market with the potential to import into 

that market when determining whether to report a change in status.

262

 

Solomon/Arenchild and NextEra argue that the proposed change significantly broadens 

the market definition captured in the metric of what constitutes a net 100 MW change in 

generation capacity.263 Solomon/Arenchild and NextEra contend that the current 

proposal implies that a megawatt outside of the market is equivalent to a megawatt 

inside of the market, which is not the case.264 Solomon/Arenchild and NextEra further 

 

262 See, e.g., Solomon/Arenchild at 4; NextEra at 11; E.ON at 10; EEI at 14. But 

see APPA/NRECA (supporting the Commission’s proposal); Golden Spread at 7

(supporting the eleven Commission proposals that APPA/NRECA supports, which are 

listed on pages 4-5 of the APPA/NRECA joint comments).

263 Solomon/Arenchild at 4; NextEra at 11.

264 Solomon/Arenchild at 4; NextEra at 11 (stating that the proposal appears to 

assume that 100 MW (or even one megawatt) added to a first-tier market should be 

treated no differently than 100 MW added in the relevant geographic market).
Docket No. RM14-14-000 133

argue that the Commission’s proposal reinstates the “hub and spoke” methodology, 

which attributed all capacity controlled by the seller and its affiliates in the relevant and 

first-tier markets to the seller, and was properly disposed of by the Commission because 

megawatts added in first-tier markets cannot necessarily be imported, unless there is a 

firm transmission reservation, which is a distinction the proposal fails to address.265 

Solomon/Arenchild propose corresponding revisions to the Commission’s proposed 

regulatory text.266

218. EEI contends that the Commission should not attribute changes in generation in 

one market to another market, even if the markets are first-tier to one another.267 EEI 

explains that the 100 MW threshold should be measured for each market separately, 

without adding changes in first-tier markets, for two reasons.268 First, the focus of the 

Commission’s market power analyses has always been on the default balancing 

authority area or other market in which market-based rate authorization is sought, 

informed by transmission capability to import generation into that market, but not by 

generation ownership in adjacent markets.269 EEI argues that there seems to be little 

reason to expand the change in status reporting requirement to mix changes in 

 

265 Solomon/Arenchild at 4; NextEra at 11. 

266 Solomon/Arenchild at 5.

267 EEI at 14.

268 Id.

269 Id.
Docket No. RM14-14-000 134

generation ownership in the relevant geographic market and the adjacent first-tier 

markets, which would be the subject of a separate study if market-based rate 

authorization is sought in those markets.270 Second, EEI is concerned that the expansion 

of the change in status reporting requirement for generation ownership to account for 

generation in the first-tier markets would create confusion.271 EEI states that this would 

complicate the tracking of generation and the application of the 100 MW threshold in 

the various markets and will not produce commensurate benefits.272 EEI therefore 

proposes that each market should be treated independently for the purpose of change in

status reporting.273 EPSA adds that any increase in megawatts in a first-tier market 

would already be reflected in the analysis of that particular first-tier market and argues 

that amending the current regulations to require sellers to account for such increases 

separately would be redundant and serve to substantially increase the burden on such 

sellers.274

219. E.ON notes that the Commission proposes to require a seller to notify the 

Commission when it becomes affiliated with “100 MW or more in any relevant 

 

270 Id.

271 Id.

272 Id.

273 Id. at 15. EPSA also argues that the proposal would complicate the tracking of 

generation and similarly recommends that the Commission to treat each market 

separately. EPSA at 8.

274 EPSA at 9. 
Docket No. RM14-14-000 135

geographic market”275 and requests the Commission clarify that the “any relevant 

market” language is limited to the applicable geographic region and applicable first-tier 

markets.276 E.ON further notes that the Commission states in the NOPR that this 

notification requirement would extend to “cumulative increases of 100 MW or more in a 

new market that has not previously been studied because, once the seller has generation 

in that market, it is a relevant geographic market for that seller”277 and states that it 

struggles to understand the benefit of this extended notification requirement and the 

Commission’s definition of a new “relevant” market.278 

220. Several commenters oppose the Commission’s proposal to use nameplate 

capacity to calculate the 100 MW change in status threshold.279 Solomon/Arenchild 

argue that the proposal creates a disconnect between the asset appendix capacity ratings 

and indicative screens capacity ratings because most indicative screens are based on 

seasonal (summer/winter), not nameplate, ratings, and many sellers report summer 

 

275 E.ON at 10 (citing NOPR, FERC Stats. & Regs. ¶ 32,702 at P 96) (emphasis 

added by E.ON).

276 Id. at 10. E.ON uses the following example: If a seller owns or controls a 

generation facility in PJM and obtained market-based rate authorization, the fact that a 

new affiliate may own or control 100 MW or more of new generation in the CAISO 

market has no relevance to whether the seller in PJM lacks horizontal market power.

277 Id. (citing NOPR, FERC Stats. & Regs. ¶ 32,702 at P 96).

278 Id.

279 See, e.g., Solomon/Arenchild at 3; EEI at 15; EPSA at 8-9; E.ON at 13; Idaho 

Power at 3-4.
Docket No. RM14-14-000 136

ratings only in their asset appendix.280 Solomon/Arenchild therefore propose that the 

Commission allow sellers to use either nameplate or seasonal ratings and, if applicable, 

five-year averages, for determining the 100 MW threshold for the notice of change in 

status.281 Solomon/Arenchild and EEI argue that the Commission should allow energylimited resources, in particular, to report five-year averages.

282

 

221. Similarly, E.ON states that, if an affiliate of a market-based rate seller acquires an 

interest in or builds 100 MW or more of energy-limited generation, the Commission 

may already have on file five years of historical average capacity ratings or EIA-derived 

data for the energy-limited generation and argues that it would be a “mismatch” to apply 

nameplate rating to the energy-limited generation for the purposes of triggering any 

notice of change in status filing requirement.283 Therefore, E.ON requests that, to the 

extent the 100 MW threshold remains, the Commission revise its regulations in section 

35.42(a)(1) to provide that a market-based rate seller submit a notice of change in status 

where there are “cumulative net increases . . . of 100 MW or more of nameplate capacity 

or as otherwise has been reported to the Commission.”284 Idaho Power adds that while 

using nameplate ratings across all generation types may provide consistency, it does not 

 

280 Solomon/Arenchild at 3.

281 Id.

282 Id.; EEI at 15.

283 E.ON at 13. 

284 Id. E.ON’s proposed change is illustrated in italics. 
Docket No. RM14-14-000 137

provide a proper basis for evaluation when comparing, for example, variable generation 

(i.e., wind, solar) with thermal generation (i.e., natural gas).285

222. Other commenters argue that notices of change in status need not be filed in 

certain circumstances.286 FirstEnergy argues that the Commission’s approval of a 

transaction under section 203 of the FPA should obviate the need for a subsequent 

change in status report and further Commission review under section 205 of the FPA.287 

FirstEnergy states that it is unaware of any instance in which the Commission authorized 

a merger of generation facilities under section 203 of the FPA and later found that the 

merged entity fails the standard for selling electricity at market-based rates in any 

relevant geographic market.288 FirstEnergy further claims that its recommendation will 

reduce the regulatory burden on sellers without adversely affecting the Commission’s 

ability to protect consumers.289

223. Additionally, AEP and E.ON argue that the Commission should eliminate 

altogether the notice of change in status requirement for sellers within RTOs. AEP 

explains that, to the extent market power concerns are implicated by a market-based rate 

seller’s acquisition or new affiliation, the extensive Commission-approved RTO market 

 

285 Idaho Power at 3-4. 

286 See, e.g., FirstEnergy at 10, 11; AEP at 6; E.ON at 8-9, 11.

287 FirstEnergy at 10. 

288 Id.

289 Id. at 11.
Docket No. RM14-14-000 138

monitoring and mitigation rules adequately prevent the exercise of market power 

without the need for the seller to file an additional report.290

224. E.ON requests that the Commission clarify that a notice of change in status filing 

is not necessary where an affiliate of a market-based rate seller is granted market-based 

rate authorization.291 E.ON also recommends that the Commission revise its policies so 

that only one substantive filing is submitted to the Commission.292

225. NextEra claims that this notice of change in status proposal is confusing in light 

of another NOPR proposal to eliminate the requirement to provide indicative screens 

where all of a seller’s and its affiliates’ generation in the relevant market is committed 

under long-term power purchase agreements.293 NextEra states that the proposed 

revised text of section 35.42(a)(1) of the Commission’s regulations provides only a 

bright line test for notices of change in status based on nameplate capacity in the 

relevant geographic market and first-tier markets, thus ignoring the long-term power 

purchase agreements.294 NextEra suggests that, if the Commission adopts this new 

 

290 AEP at 6. E.ON makes similar arguments. See E.ON at 8-9 (emphasizing that 

the notice of change in status would simply repeat what the market-based rate seller has 

already told the Commission, namely, that the market-based rate seller is relying on RTO 

mitigation).

291 E.ON at 11. 

292 Id. (arguing that an initial market-based rate application of the new affiliate 

should suffice to address all other relevant, affiliated market-based sellers). 

293 NextEra at 11. 

294 Id.
Docket No. RM14-14-000 139

requirement, it should explain how section 35.42(a) of the Commission’s regulation 

should be interpreted when generation is subject to a long-term power purchase 

agreement.295 EEI encourages the Commission to find additional ways to streamline the 

change in status reporting requirements. EEI offers two examples: (1) the Commission 

should indicate that minor changes in organization or other information covered by the 

change in status reporting requirements need not be reported individually but can be 

cumulated to include with a next change in status filing, and (2) the Commission should 

consider providing additional relief from change in status reporting to companies based 

on the Commission’s experience with the change in status requirements over the past 

decade (e.g., the Commission should consider increasing the 100 MW thresholds).296 

226. EPSA notes that sellers are required to report a change in status when an 

additional 100 MW in a relevant geographic market is attained, but states that it is 

unclear whether the change in status reporting requirement is then “reset” and a notice of 

change in status is necessary when another 100 MW of controlled generation is 

obtained, or once the 100 MW threshold is attained, if all new controlled generation in 

excess of 100 MW must be reported.297 EPSA seeks clarification that a notice of change 

 

295 Id. at 12. 

296 EEI at 16.

297 EPSA at 11-12. 
Docket No. RM14-14-000 140

in status must be submitted each time a seller attains a cumulative 100 MW of controlled 

generation.298 

227. FirstEnergy recommends that, in addition to the proposal to relieve RTO/ISO 

sellers from the obligation to file the indicative screens, the Commission should relieve 

RTO/ISO sellers from the obligation to submit notices of change in status relating to 

increases in generation capacity. Similarly, AEP recommends that the Commission 

relieve RTO/ISO sellers from the obligation to submit notices of change in status 

altogether. EEI encourages the Commission to consider providing broader relief from 

change in status reporting to utilities with FERC-approved market power mitigation 

measures to reduce the burden associated with the market-based rate program. EEI 

states that the same principles underlying the proposed exemption of sellers with FERCapproved market power mitigation from providing the indicative horizontal market 

screens in their market power updates could apply equally to the overall change in status 

reporting requirements. 

c. Commission Determination

228. We adopt the NOPR proposal with certain modifications and clarifications. In 

the NOPR, the Commission proposed to apply the 100 MW threshold to a seller’s and/or 

its affiliates’ generation capacity in each relevant market and first tier market(s), and to 

also apply the 100 MW threshold to each new relevant market (not previously studied) 

in which a seller and/or its affiliates acquire a cumulative net increase of 100 MW. The 

 

298 Id.
Docket No. RM14-14-000 141

NOPR also proposed to require that the 100 MW threshold for change in status filings 

be calculated based solely on a generator’s nameplate capacity rating. 

229. We believe that the Solomon/Arenchild and NextEra comments with respect to 

the calculation of the 100 MW threshold have merit299 and that generation capacity in 

the first tier markets should not be treated the same as capacity located in the seller’s 

relevant geographic market/study area. We recognize that 100 MW located outside of 

the study area is only equivalent to 100 MW inside when there is a long-term firm 

transmission reservation to import the 100 MW.

230. Therefore, we will modify the proposal set forth in the NOPR. The 100 MW 

threshold for reporting a change in status will apply to a seller’s and/or its affiliates’ net 

generation capacity additions in each individual market, but will exclude markets and 

balancing authority areas that are first-tier to the seller’s study area. This means a seller 

need not consider its and its affiliates new generation, including generation from longterm purchase agreements, in first-tier areas in determining whether it has reached the 

100 MW threshold. 

231. However, we confirm that, consistent with the NOPR, the 100 MW threshold 

applies to each new relevant market (not previously studied) in which a seller and/or its 

affiliates acquire a cumulative net increase of 100 MW. To find otherwise would allow 

a loophole where an applicant could request and be granted market-based rate authority 

 

299 NextEra at 11; Solomon/Arenchild at 4.
Docket No. RM14-14-000 142

with a small amount of generation in one market, qualify as a Category 1 seller, and then 

accumulate large amounts of generation in other markets in the same region such that 

the seller could become Category 2 in the region without notifying the Commission. In 

addition, applying the 100 MW threshold to each new relevant market ensures that 

sellers study the generation acquired in any additional market that meets or exceeds this 

threshold.

232. Further, we believe that the comments opposing the Commission’s proposal to 

require use of nameplate capacity to calculate the 100 MW change in status threshold 

have merit.300 Therefore, we will revise the NOPR proposal and permit sellers to use 

nameplate or seasonal capacity ratings for the 100 MW threshold for most generation 

and allow energy-limited generation to use either nameplate or a five-year average 

capacity factor.301

233. We disagree with FirstEnergy’s contention that section 203 approvals should 

obviate the need for subsequent change in status filings for further Commission review 

under section 205. The Commission’s analyses under sections 203 and 205 consider 

different criteria for approving transactions; therefore, it is not a given that a seller that 

passes a section 203 analysis will pass a section 205 analysis. Furthermore, the data 

 

300 E.g., E.ON at 13 ; EEI at 15; Idaho Power at 3-4; Solomon/Arenchild at 3.

301 However, consistent with our finding in this Final Rule regarding use of 

nameplate capacity for solar photovoltaic facilities, for change in status threshold 

purposes, sellers should use nameplate capacity for such facilities. NOPR, FERC Stats. 

& Regs. ¶ 32,702 at P 104. 
Docket No. RM14-14-000 143

required for the Commission’s analyses under FPA sections 203 and 205 differ; section 

203 filings are prospective, with studies based on projected data, whereas the change in 

status filings under section 205 require studies based on historical data. 

234. Additionally, we reject AEP’s, E.ON’s, FirstEnergy’s, AEP’s, and EEI’s requests 

that the Commission eliminate the change in status requirements for sellers located in 

RTOs/ISOs.302 AEP states that the Commission-approved market monitoring and 

mitigation rules adequately prevent the exercise of market power without the need for 

the seller to file an additional report.303 As explained above, we are not prepared at this 

time to adopt the NOPR proposal to relieve sellers in RTO/ISO markets of the obligation 

to file indicative screens.304 Therefore, we will not relieve sellers in RTO/ISO markets 

of their obligation to file notices of change in status. 

235. We reject EEI’s request to report minor changes in organization or other 

information covered by the change in status requirements cumulatively with another 

change in status filing instead of in separate change in status filings. Any change in other 

information covered by the change in status requirements must be reported within 30 

days of the change. We interpret EEI’s request to be that “minor change” be permitted to 

be filed more than 30 days after the change, i.e., at the time of the next change in status 

 

302 AEP at 3; E.ON at 8-9.

303 AEP at 6.

304 Moreover, we note that the NOPR did not propose to completely eliminate the 

requirement for RTO sellers to file triennial updated market power analyses but instead 

proposed to eliminate the need to file indicative screens with their triennials. 
Docket No. RM14-14-000 144

filing. Timely notice of reportable changes in status are part of the Commission’s ex post

analysis;

305

 it is not appropriate to exempt any changes from being reported within 30 

days, particularly given that it is unclear when, if at all, those changes would ever be 

reported. 

236. Additionally, we reject EEI’s proposal to increase the 100 MW change in status 

reporting threshold.306 We believe that the 100 MW threshold is reasonable, particularly 

given the trend towards building smaller units. Further, changing the value of the 

megawatt threshold was not proposed in the NOPR; thus, the proposal is outside the 

scope of this rulemaking.

237. With regard to E.ON’s request that the Commission clarify that the “any relevant 

market” language is limited to the applicable geographic region and applicable first-tier 

markets,

307 we clarify that any relevant market refers to a market in which a seller 

 

305 Cal. ex rel. Harris v. FERC., 784 F.3d 1267, 1276 (9th Cir. 2015) (“When we 

approved market-based ratemaking in Lockyer, we repeatedly emphasized the importance 

of the ‘dual requirement of an ex ante finding of the absence of market power and 

sufficient post-approval reporting requirements.’” (citing Cal. ex rel. Lockyer v. FERC, 

383 F.3d 1006, 1013 (9th Cir. 2004)). 

306 EEI at 16.

307 E.ON at 10. E.ON uses the following example: If a seller owns or controls a 

generation facility in the PJM market and obtained market-based rate authorization, the 

fact that a new affiliate may own or control 100 MW or more of new generation in the 

CAISO market has no relevance to whether the seller in the PJM market lacks horizontal 

market power.
Docket No. RM14-14-000 145

already has generation located and acquires an additional 100 MW or a new market that 

the seller had not studied previously. 

238. Additionally, in response to E.ON’s requests that the Commission clarify if a 

seller needs to submit a change in status if it acquires generation in an RTO market 

where it sells energy products, and clarify whether a seller has to file a change in status 

when an affiliate is granted market-based rate authority, we clarify as follows. A seller 

should submit a change in status when it acquires generation in any market, including an 

RTO market where it sells electric products. Further, if a seller’s affiliate is granted 

market-based rate authority, and that results in 100 MW or more of new generation 

capacity in a market, then the seller will have to file a corresponding change in status. 

Therefore, we reject E.ON’s recommendation to revise the change in status policy so 

that only one substantive filing is submitted to the Commission.308

239. In response to NextEra’s contention that the notice of change in status proposal is 

confusing because it conflicts with the NOPR proposal to eliminate the requirement to 

provide indicative screens where all of a seller’s and its affiliates’ generation in the 

relevant market is committed under long-term power purchase agreements, we clarify as 

follows.

309

 For purposes of the change in status requirement in section 35.42(a)(1), 

long-term firm purchases should be treated as seller or affiliate-owned or controlled 

 

308 E.ON at 11 (arguing that an initial market-based rate application of the new 

affiliate should suffice to address all other relevant, affiliated market-based sellers). 

309 NextEra at 11. 
Docket No. RM14-14-000 146

generation capacity in the determination of the 100 MW threshold. Thus, a seller need 

not make a change in status filing every time it enters into a new long-term firm 

purchase agreement, but would need to submit a change is status when its overall 

cumulative increase in generation is 100 MW. The seller would need to revise its asset 

appendix to include the long-term purchase agreement(s). In addition, we clarify that a 

market-based rate seller that adds new generation capacity that is fully committed to a 

non-affiliated buyer need not count that capacity toward the 100 MW threshold. 

240. We clarify in response to EPSA that if a seller acquires more than 100 MW, it 

should report all of the newly acquired generation to ensure that the net change in 

generation capacity is reported in a timely manner. Furthermore, once a seller files a 

change in status for a net increase of 100 MW or more of generation capacity, the 

threshold is effectively reset such that the seller must file a change in status each time it 

acquires an additional 100 MW or more of generation capacity.

2. New Affiliation and Behind-the-Meter Generation

a. Commission Proposal

241. Market-based rate sellers are required to make a change in status filing when, 

among other requirements in section 35.42 of the Commission’s regulations, they become 

affiliated with entities that: (1) own or control generation; (2) own or control inputs to 

electric power production; (3) own, operate, or control transmission facilities; or (4) have 

a franchised service territory. There currently is no 100 MW threshold for reporting new 

affiliations (but there is a 100 MW threshold for net increases for a seller’s owned or 

controlled generation facilities). In the NOPR, the Commission proposed to revise the 
Docket No. RM14-14-000 147

change in status regulations to include a 100 MW threshold for reporting new affiliations. 

That is, a market-based rate seller that has a new affiliation would not be required to file a 

change in status for an affiliation with an entity with generation assets until its new 

affiliations result in a cumulative net increase of 100 MW or more of nameplate capacity 

in any relevant geographic market. The Commission noted that the 100 MW threshold 

for reporting new generation strikes the proper balance between the Commission’s duty 

to ensure that market-based rates are just and reasonable and the Commission’s desire not 

to impose an undue regulatory burden on market-based rate sellers.310 Similarly, the 

Commission stated that applying the 100 MW threshold to new affiliations might ease the 

reporting burden on sellers without diminishing the Commission’s ability to identify 

possible market power. Therefore, the Commission proposed to revise section 

35.42(a)(2) of the Commission’s regulations to add a 100 MW threshold for reporting 

certain new affiliations.

242. The Commission also clarified that the requirement to submit a notice of change in 

status to report affiliation with new generation, transmission, or intrastate gas pipelines

includes reporting that asset in the seller’s asset appendix. The Commission proposed to 

amend section 35.42(c) to clarify that sellers must include all new affiliates and any 

assets owned or controlled by the new affiliates in the asset appendix. 

 

310 Reporting Requirement for Changes in Status for Public Utilities with MarketBased Rate Authority, Order No. 652, FERC Stats. & Regs. ¶ 31,175, at P 68, order on 

reh’g, 111 FERC ¶ 61,413 (2005).
Docket No. RM14-14-000 148

243. The Commission further proposed in the NOPR that “all assets” include behindthe-meter generation and qualifying facilities.311 However, the Commission proposed to 

allow sellers to aggregate their behind-the-meter generation by balancing authority area 

or market into one line on the list of generation assets. Similarly, the Commission

proposed to allow sellers to aggregate their qualifying facilities under 20 MW by 

balancing authority area or market into one line on the list of generation assets.

244. The Commission also proposed that sellers should include these assets in their 

indicative screens, as well as in their asset appendix and that sellers should include this 

generation when calculating the 100 MW change in status threshold and the 500 MW 

Category 1 threshold.

b. Comments

245. Commenters generally support the Commission’s proposal to revise the 

change in status regulations to include a 100 MW threshold for reporting new 

affiliations.312 Specifically, EEI supports the Commission’s proposal and adds that the 

 

311 Accordingly, the appendix must list all generation assets owned (clearly 

identifying which affiliate owns which asset) or controlled (clearly identifying which 

affiliate controls which asset) by the corporate family by balancing authority area, and by 

geographic region, and provide the in-service date and nameplate or seasonal ratings by 

unit. As a general rule, any generation assets included in a seller’s market power study 

should be listed in the asset appendix. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 

895.

312 See, e.g., EEI at 15-16; FirstEnergy at 11-12; SunEdison at 9 (noting that this 

proposal is especially important to a company like SunEdison that routinely acquires or 

becomes affiliated with new entities that own small amounts of capacity); NRG 

Companies at 11-12; APPA/NRECA at 4; Golden Spread at 7.
Docket No. RM14-14-000 149

Commission should consider allowing a seller the option to file an addendum to its 

Appendix B asset list with the change in status filing, instead of a complete new list, to 

show the specific changes in generation.313 FirstEnergy also supports the Commission’s 

proposal, but argues that, if the new affiliation has previously been reviewed by the 

Commission pursuant to its authority under section 203 of the FPA, the Commission 

will derive no significant benefit by requiring the seller to submit a notice of change in 

status relating to such affiliation and recommends that the reporting requirement be 

further limited.314 

246. FirstEnergy supports the proposal to require generating capacity associated 

with qualifying facilities and behind-the-meter generation to be considered when 

determining the applicability of the Commission’s rules for filing notices of change in 

status and updated market power analyses.315 FirstEnergy contends that, to the extent 

qualifying facilities may be owned by or affiliated with entities owning other generation 

resources, there is no valid reason why owners of qualifying facilities and/or behind-themeter generation resources should not be subject to the same rules as those applicable to 

other market participants.316

 

313 EEI at 16.

314 FirstEnergy at 11. 

315 Id. at 12. 

316 Id.
Docket No. RM14-14-000 150

247. Several commenters oppose the Commission’s proposal to include behindthe-meter generation as part of the 100 MW change in status threshold.317

 NRG 

Companies and NextEra argue that requiring the inclusion of behind-the-meter 

generation in asset appendices and market power analyses would impose a substantial 

burden on sellers.318 NRG Companies and NextEra also argue that no useful purpose 

will be served by the inclusion of behind-the-meter generation that is committed to onsite consumption and not available to the grid.319

 NRG Companies and NextEra add that 

such generation may involve net metering, which they state does not involve wholesale 

sales or transmission implicating the Commission’s jurisdiction.320 

248. NRG Companies, NextEra, and SunEdison argue that behind-the-meter 

generation does not contribute to market power and should be excluded from the asset 

 

317 See, e.g., NextEra at 12; NRG Companies at 2-3 (stating, however, that the 

proposal makes sense as to qualifying facilities); SunEdison 5-8. 

318 NRG Companies at 3 (stating that distributed generation projects can be 

developed and installed in very short time periods and tracking these projects with the 

frequency required to maintain accurate asset appendices would be burdensome on any 

entity whose affiliates are active in this area); NextEra at 12 (stating that the burden to 

include behind-the-meter generation will increase significantly, if there are numerous 

facilities within a corporate family). 

319 NextEra at 12-13 (stating that, because of their small size, such facilities are 

unlikely to affect meaningfully any evaluation of market power in the indicative screens 

and adding that there would be little or no value to the Commission in submitting a notice 

of change in status in addition to the initial applications and market power updates); NRG 

Companies at 2-3.

320 NextEra at 13; NRG Companies at 2-3 (citing Sun Edison LLC, 129 FERC 

¶ 61,146, at P 18 (2009) (Sun Edison)).
Docket No. RM14-14-000 151

appendix.321 SunEdison argues that it is inconsistent to require listing of assets that are 

not engaged in wholesale power sales in the interstate power market and therefore 

cannot and do not contribute to the seller's market share or market power.322 SunEdison 

argues that, because the purpose of an asset appendix is to provide data to be used in the 

Commission’s assessment of a seller’s and its affiliates’ market power in jurisdictional 

wholesale markets, the Commission should find that assets that do not participate in 

wholesale markets should not be included in the asset appendix.323 SunEdison further 

contends that, since behind-the-meter facilities are not physically capable of engaging in 

coordinated interactions or arrangements with generation that sells power in 

jurisdictional markets, there is no need to include them in a seller’s asset appendix.324 

SunEdison requests that, if the Commission determines it necessary to report behind-the-

 

321 SunEdison at 4 (stating that the requirement will be “unduly burdensome” for a 

company that owns “hundreds of small behind-the-meter solar projects” and whose 

business plan is for it and its affiliates to develop and acquire “thousands of additional 

similar projects” and citing Commission precedent where the Commission held that netmetered sales do not represent jurisdictional wholesale sales or transmission). SunEdison 

also references the White House and U.S. Department of Energy initiative to streamline 

the permitting, installation, and interconnection processes and states that reducing 

unnecessary administrative burdens on companies that develop solar energy projects is 

one way to help achieve this goal. Id. at 4-5. 

322 Id. at 5.

323 Id. at 7.

324 Id.
Docket No. RM14-14-000 152

meter generation in the asset appendix, it should exempt from this requirement facilities 

with a net capacity of one MW or less.325

249. El Paso recognizes the increasing role of behind-the-meter generators in 

wholesale power markets and does not oppose the Commission's inclusion of behindthe-meter generation in the indicative screens.326

 However, El Paso cautions the 

Commission to recognize that for some systems, the output of these generators will have 

already been reflected in the net load reported in the FERC Form No. 714 (Annual 

Electric Control and Planning Area Report), thus resulting in double-counting a utility’s 

capacity and, consequently, overestimating its supply.327 El Paso requests that the 

Commission further refine its reporting directive to instruct sellers to include behindthe-meter generation in their indicative screens to the extent such generation is not 

already netted against load for purposes of their FERC Form No. 714 reporting.328

250. Other commenters seek clarification of the Commission’s proposed changes to 

the change in status reporting requirements, as they relate to behind-the-meter 

 

325 Id. at 9 (citing Revisions to Form, Procedures, and Criteria for Certification of 

Qualifying Facility Status for a Small Power Production or Cogeneration Facility, Order 

No. 732, 75 Fed. Reg. 15,950 (Mar. 30, 2010), FERC Stats. & Regs. ¶ 31,306, at P 34 

(2010) and comparing its argument for why behind-the-meter generation should not be 

included in a seller’s asset appendix to the Commission’s reasoning in Order No. 732 to 

exempt small facilities from the Commission’s Qualifying Facility status filing 

requirement).

326 El Paso at 4.

327 Id.

328 Id.
Docket No. RM14-14-000 153

generation. Specifically, EPSA argues that, if a seller has behind-the-meter generation 

that is used solely to operate equipment for production (such as an oil or gas operation 

that uses behind-the-meter generation to produce oil or gas), such behind-the-meter 

generation should not be counted towards the 100 MW threshold because that generation 

is never offered or sold into the market. EPSA recommends the Commission clarify that 

any such behind-the-meter generation that is wholly self-consumed would not count 

towards the 100 MW threshold.329 SoCal Edison requests the Commission clarify 

whether behind-the-meter generation includes generation not synchronized to the grid 

(i.e., generation that cannot be used for wholesale power sales), since all generation is 

typically behind some meter.330 SoCal Edison does not believe, for example, that a 

back-up generator used to power a control center in the event of a power outage needs to 

be included in a seller’s asset appendix and seeks confirmation to that effect.331 SoCal 

Edison also requests that the Commission clarify whether it will permit sellers to 

aggregate long-term firm purchases from small generators (such as qualifying facilities 

under 20 MW) by balancing authority area or market into one line on the list of 

 

329 EPSA at 11. 

330 SoCal Edison at 19 (emphasis in original).

331 Id.
Docket No. RM14-14-000 154

generation assets.332 SoCal Edison argues that such aggregation should be permitted to 

relieve the burden that otherwise would be imposed.333

c. Commission Determination

251. We adopt the NOPR proposal to establish a 100 MW threshold for reporting new 

affiliations in change of status filings. A market-based rate seller that has a new 

affiliation will not be required to file a change in status for an affiliation with an entity 

with generation assets until its new affiliations result in a cumulative net increase of 100 

MW of capacity in a relevant geographic market.334 The 100 MW threshold for new 

affiliations will be determined in exactly the same manner as the 100 MW threshold is 

determined for other notices of change in status. As explained above, the 100 MW 

threshold will be determined for each relevant geographic market but will not consider 

generation capacity additions in first-tier markets. We believe the 100 MW threshold 

strikes a reasonable balance between reducing reporting burden on sellers while keeping 

the Commission informed about potential market power concerns. We clarify that the 

100 MW reporting threshold for new affiliations is not separate nor distinct from the 100 

MW thresholds for reporting power purchase agreements or owned generation as 

 

332 Id. at 23.

333 Id.

334 However, if a seller files a notice of change in status for another reason, e.g., to 

report the entrance into a power purchase agreement of more than 100 MW, the seller 

should note that it has a new affiliate with market-based rate authority and include that 

new affiliate and any related assets in the seller’s asset appendix.
Docket No. RM14-14-000 155

discussed elsewhere in this Final Rule. In other words, if a seller becomes newly 

affiliated with 50 MW of generation in a balancing authority area or market and 

experiences an increase of 50 MW of owned generation in that same balancing authority 

area or market, the 100 MW reporting threshold would be triggered. Similarly, a seller 

with a newly acquired 50 MW power purchase agreement in that same balancing 

authority area of market would also trigger the reporting threshold. 

252. However, we do not adopt the NOPR proposal to count behind-the-meter 

generation in the 100 MW change in status threshold and 500 MW Category 1 seller 

status threshold and to include such generation in the asset appendices and indicative 

screens.

253. We agree with El Paso that the output of behind-the-meter generation should 

be reflected in the load data reported in the FERC Form No. 714. That is, the load 

reported in FERC Form No. 714 reflects the fact that the load is lower than it otherwise 

would be if a portion of the load were not served by behind-the-meter generation. 

Additionally, since behind-the-meter generation is netted out of the load data, requiring 

sellers to count behind-the-meter generation as installed capacity could result in doublecounting a portion of the seller’s generation capacity. Moreover, we clarify that behindthe-meter generation that is consumed on-site by the host load and not sold into the 

wholesale market, or is not synchronized to the transmission grid, is not relevant to the 

Commission’s horizontal market power analysis.

254. Given our decision not to require sellers to include behind-the-meter 

generation in their asset appendices, indicative screens, and for purposes of calculating 
Docket No. RM14-14-000 156

the 100 MW change in status threshold and 500 MW Category 1 threshold, we will not 

address the remaining requests for clarifications made by NRG Companies, NextEra, 

SunEdison, EPSA, and SoCal Edison.

255. Finally, we clarify that qualifying facilities that are exempt from FPA section 

205335 and facilities that are behind-the-meter facilities do not need to be reported in the 

asset appendix or indicative screens. However, many qualifying facilities do have 

market-based rate authority and the capacity of these facilities should be reported in the 

screens, asset appendix and in determining the 100 MW threshold.

3. Reporting of Long-Term Firm Purchases

a. Commission Proposal

256. As discussed elsewhere in this Final Rule, the Commission proposed to 

require reporting of long-term firm purchases in the indicative screens and also proposed 

to include such contracts when determining the 100 MW threshold for change in status 

filings.336

b. Comments

257. The comments addressed in the discussion on treatment of long-term contracts 

generally encompass the issues in this section. However, SoCal Edison states that the 

Commission should clarify that it will permit long-term firm purchase aggregation from 

 

335 See 18 CFR 292.601(c)(1).

336 NOPR, Stats. & Regs. ¶ 32,702 at P 100.
Docket No. RM14-14-000 157

small generators, such as qualifying facilities under 20 MW. SoCal Edison requests that 

such aggregation be permitted to relieve the burden that otherwise would be imposed.337 

c. Commission Determination

258. The requirement to report long-term firm purchases in the asset appendix and 

indicative screens and to require that such contracts be counted towards the 100 MW 

threshold is discussed elsewhere in this Final Rule.338 With respect to SoCal Edison’s 

request regarding aggregation of long-term firm purchase agreements, we clarify that 

aggregation of such agreements will be permitted in the asset appendix if certain 

conditions are met. Specifically, we will allow aggregation of long-term firm purchase 

agreements from small generators only if the information in these columns in the asset 

appendix is identical for all agreements: “[E] Market / Balancing Authority Area,” “[F] 

Geographic Region,” “[G] Start Date (mo/da/yr),” and “[H] End Date (mo/da/yr).” 

Aggregating agreements with different start dates or end dates or agreements in different 

Market /Balancing Authority Areas would defeat the usefulness of collecting such 

information. We also clarify that a seller that meets these criteria can aggregate such 

agreements but would need to use column “[I] End Note” to report different docket 

numbers and/or names of the filing entities and seller(s) in the End Note list of the asset 

appendix. 

 

337 SoCal Edison at 23.

338 See supra Section IV.C.1.
Docket No. RM14-14-000 158

D. Asset Appendix

259. The Commission proposed clarifications and revisions to the required appendix 

that contains the lists of generation and transmission assets.

1. Changes to the Existing Columns

a. Commission Proposal

260. The Commission proposed to make three changes to the existing columns in the 

asset appendix. The Commission proposed to change a column heading on both assets

lists from “Balancing Authority Area” to “Market/Balancing Authority Area” to reflect 

the correct location for assets in organized markets as well as in balancing authority 

areas. The second proposal was to change a column heading on both asset lists from 

“Geographic Region (per Appendix D)” to “Geographic Region” because there have 

been changes to some regions since the Commission originally published the region map 

in Appendix D of Order No. 697. Finally, the Commission proposed to change the 

heading for the “Nameplate and/or Seasonal Rating” column of the generation list to 

“Capacity Rating (MW): Nameplate, Seasonal, or Five-Year Average” to clarify that 

this column requires capacity ratings in megawatts and to reflect that each submission in

the asset appendix should use either “nameplate,” “seasonal,” or “five-year average”

ratings to reflect the rating used throughout the filing for a particular generation 

technology. The Commission indicated that these proposed changes would ensure 

consistency across filings and allow the industry and Commission staff to better utilize 

the information contained in the asset lists.
Docket No. RM14-14-000 159

261. The Commission further proposed to clarify that the asset lists should not contain 

any information other than what is required in the respective columns. For instance, 

sellers frequently include footnotes in their appendices that cause the appendices to 

become unwieldy and difficult to read or understand. Sellers sometimes explain in these 

footnotes that some facilities are partially owned, that some affiliates included in their 

asset lists may not actually be affiliates but are included out of an abundance of caution, 

or that a facility is expected to come on-line or off-line at some future date. The 

Commission discouraged any such footnotes and directed that any such representations 

be made in the filing transmittal letter.

262. Thus, the Commission proposed to modify the example of the required appendix 

found in Appendix B to Subpart H of Part 35 of the Commission’s regulations to 

incorporate these changes.

b. Comments

263. Few commenters express concern about the Commission’s proposed changes to 

the existing columns in the asset appendix.339 Solomon/Arenchild are concerned that the 

proposal to change the heading for capacity ratings column from “Nameplate and/or 

Seasonal Rating” to “Capacity Rating (MW): Nameplate, Seasonal, or Five-Year 

Average” may introduce “another potential source of inconsistency across filings” and

therefore suggest that the Commission add another column to the asset appendix to 

allow a seller to report nameplate or seasonal ratings, as well as the five-year average 

 

339 See, e.g., Solomon/Arenchild at 7; EEI at 17.
Docket No. RM14-14-000 160

rating, if the seller elects to use five-year average ratings.

340 EEI states that the 

Commission’s proposed changes to existing columns seem appropriate, but would 

encourage the Commission not to change the geographic regions without advance notice

and opportunity for comment by market participants in those regions.341

264. Several commenters oppose the Commission’s proposal to clarify that asset lists 

should not contain any information other than what is required in the respective 

columns.342 EPSA notes that the reason sellers include footnotes and other “extraneous 

information” is to avoid allegations that the sellers have misled the Commission.

343

 

EPSA requests that the Commission add a separate column to the asset appendix for 

explanatory notes and clarifications, instead of prohibiting the use of footnotes.344 NRG 

Companies echo EPSA’s concerns and state that sellers include explanatory notes to 

avoid misleading the Commission about matters that are too complex to be depicted 

fully and accurately in the prescribed fields.345 NRG Companies add that providing the 

explanatory notes in the transmittal letter will not be an adequate substitute for 

 

340 Solomon/Arenchild at 7 & Attachment 1 (illustrating their proposed additional 

column to the asset appendix).

341 EEI at 17.

342 See, e.g., EEI at 18; El Paso at 5; EPSA at 13; NRG Companies at 6.

343 EPSA at 13.

344 Id.

345 NRG Companies at 6.
Docket No. RM14-14-000 161

appropriate notes in the asset appendix itself.346 El Paso argues that discouraging sellers 

from adding footnotes to their asset appendices could cause confusion amongst industry 

particularly if the Commission creates a searchable public database from these asset 

appendices because sellers may unintentionally provide misleading information.

347

 EEI 

notes that this clarification seems unnecessary and could inhibit sellers from including 

helpful information in the asset appendix.348

c. Commission Determination

265. We adopt the proposed changes to the existing columns in the asset appendix on 

both asset lists from “Balancing Authority Area” to “Market/Balancing Authority Area” 

to reflect the correct location for assets in organized markets, as well as in balancing 

authority areas. We also adopt the proposed column heading change from “Geographic 

Region (per Appendix D)” to “Geographic Region” because there have been changes to 

some regions since the Commission originally published the region map in Appendix D 

of Order No. 697. We note, with regard to EEI’s comment, that removing the reference 

to Appendix D removes an outdated reference to the Appendix in Order No. 697. 

Further, to aid in identification of similarly named columns in the asset lists, we are 

 

346 Id. at 7.

347 El Paso at 5 (arguing that members of the public may not take the time to 

search the original transmittal letter that would explain a seller’s ownership).

348 EEI at 18.
Docket No. RM14-14-000 162

adding an alphabetic label to each column in the asset lists in the new Asset 

Appendix.349

266. We do not adopt the proposal to change the heading for the “Nameplate and/or 

Seasonal Rating” column of the generation list to “Capacity Rating (MW): Nameplate, 

Seasonal, or Five-Year Average.” Instead, in response to the Solomon/Arenchild 

comments, we will modify the generation asset list to clearly distinguish between the 

nameplate rating and an alternative rating of a generation facility. Specifically, we are 

removing the “Nameplate and/or Seasonal Rating” column and replacing it with three 

new Columns [J], [K], and [L], entitled “Capacity Rating: Nameplate (MW)”, “Capacity 

Rating: Used in Filing (MW)”, and “Capacity Rating: Methodology Used in [K]: 

(N)ampelate, (S)easonal, 5-yr (U)nit, 5-yr (E)IA, (A)lternative,” respectively.350 Sellers 

will populate Column [J] with the nameplate capacity rating of their facilities, Column 

[K] with the capacity rating attributed to that facility in the filing and any associated 

market power study, and Column [L] with the appropriate letter to indicate which rating 

 

349 For example, the first column in the generation asset list is “Filing Entity and 

its Energy Affiliates.” We have labeled that column, above the column heading, as 

Column “[A].” 

350 As discussed in this Final Rule, sellers are allowed to use alternative rating 

methodologies for different generation technologies in their market power studies. The 

“Capacity Rating: Used in Filing (MW)” column is where sellers should report the actual 

value they used in the market power analysis. If a seller uses nameplate ratings, the 

values in Column [J] “Capacity rating nameplate (MW)” and Column [K] “Capacity 

rating: used in filing (MW)” will be the same.
Docket No. RM14-14-000 163

methodology was used to derive the capacity rating used in Column [K].351 Sellers will 

need to populate every column for all facilities in the generation asset list, even facilities 

that are not discussed in a given filing. If the instant filing does not contain a market 

power study, or a particular generation asset is not included in a market power study in 

that filing, sellers should include in the generation asset list the rating that it used the last 

time the asset was included in a market power study. We believe this format addresses 

Solomon/Arenchild’s concern about consistency of the rating methodology across 

filings, while maintaining the ability to tie asset appendix ratings to those used in a 

market power analysis. 

267. Finally, we adopt the NOPR proposal to prohibit footnotes from the asset 

appendices. However, in response to commenters’ concerns about loss of clarity and 

information, we adopt EPSA’s suggestion and add a separate column to the asset 

appendix for explanatory notes and clarifications. We are adding a column entitled 

“End Note Number (Enter text in End Note Tab)” as the final column in the generation 

list (Column [M]), transmission list (Column [J]), and, as discussed below, the new 

long-term firm power purchase agreement list (Column [I]), and creating an additional 

end notes list. The end notes list will have three columns: Column [A] “End Note 

Number;” Column [B] “List (Generation, PPA, or Transmission);” and Column [C]

 

351 For example, for a seller that has decided to use nameplate ratings for all wind 

facilities in its market power studies and owns a 100 MW (nameplate) wind facility, the 

seller will place “100” in Column [J], “100” in Column [K], and “N” in Column [L].
Docket No. RM14-14-000 164

“Explanatory Note.” When a seller wants to provide more information about a 

particular facility in an asset appendix list, the seller will place a number in the 

appropriate end note column of the row listing that facility. Furthermore, the seller will 

then enter that number in Column [A] of the end notes list, specify in Column [B] which 

asset list this end note refers to, and finally, enter in Column [C] the explanatory text.

2. Reporting Power Purchase Agreements

a. Commission Proposal

268. The Commission also proposed to require sellers to include all of their long-term 

firm purchases of capacity and/or energy in their indicative screens and asset appendices, 

regardless of whether the seller has operational control over the generation capacity 

supplying the purchased power. The Commission stated that this approach will help size 

the market correctly and will establish consistent treatment of long-term firm sales and 

long-term firm purchases.352 Other sections of this Final Rule discuss the conversion of a 

power purchase agreement measured in MWh into MW values that will be entered into 

the asset appendix and indicative screens. 

b. Comments

269. Several commenters requested clarification regarding how to account for longterm firm purchases in the asset appendix. For example, SoCal Edison states that it will 

not be possible to fill out the asset appendix as currently proposed where a long-term firm 

purchase is not tied to a physical generating asset and suggests separating the appendix 

 

352 NOPR, FERC Stats. & Regs. ¶ 32,702 at PP 16, 79.
Docket No. RM14-14-000 165

into two appendices – one for seller’s/applicant’s generation and one for 

seller’s/applicant’s long-term firm purchases.353 SoCal Edison states that if the 

Commission does not change the asset appendix headings as requested, the Commission 

should hold a technical conference to address questions raised by the change in policy 

regarding the reporting of long-term firm purchases.354 NextEra opposes the reporting of

long-term power purchase agreements in the asset appendix but states that if the 

Commission decides to require this reporting it should allow the use of EIA regional data 

for facilities that do not yet have seasonal or a five-year average capacity rating.

355

 

c. Commission Determination

270. We do not find the comments opposed to reporting of long-term firm purchases in 

the asset appendix to be persuasive and adopt the NOPR proposal to require sellers to 

report all of their long-term firm purchases of capacity and/or energy in their indicative 

screens and asset appendices. However, we agree with commenters that the format of 

the generation asset list is not well suited for reporting long-term purchases. Therefore, 

we are implementing SoCal Edison’s recommendation to create a separate list for a 

seller’s long-term firm purchases.356 The new long-term purchases list has columns 

similar to the generation list, but removes several inapplicable columns (Generation 

 

353 SoCal Edison at 21.

354 Id. at 23.

355 NextEra at 13-14.

356 SoCal Edison at 21.
Docket No. RM14-14-000 166

Name, Owned By, Controlled By, and Date Control Transferred), and adds “Start Date 

(mo/da/yr)” and “End Date (mo/da/yr)” columns. 

271. NextEra requests that purchasers under a long-term firm power purchase 

agreement be allowed to use EIA regional data. As discussed above in the section on 

capacity ratings, we permit use of EIA regional data but only for energy-limited 

facilities that lack five years of operating data or for non-affiliated energy-limited 

facilities for which the seller cannot obtain operating data.357 We also will require that 

sellers de-rate all generators using the same technology in a consistent manner. Thus, if 

a purchaser can identify which generation units are fulfilling a long-term firm PPA, it 

should use the same rating methodology for that facility in its market power study that it 

is using for other generation facilities utilizing that technology.

3. Clarifications Regarding the Existing Columns

a. Commission Proposal

272. The Commission noted that its post-Order No. 697 experience has been that, with 

respect to the column in the list of generation assets that is currently labeled “Nameplate 

and/or Seasonal Rating,” some sellers report only the portion of the capacity that they 

own,

358 whereas other sellers report the entire capacity of the facility. Additionally, 

 

357 As discussed above, the Commission will not permit de-rating of solar 

photovoltaic facilities. See supra Section IV.A.6.c.i.

358 The Commission noted that it has not permitted market-based rate sellers to 

dilute the ownership share of generation attributed to the seller or its affiliates based on 

multiplying successive shares of partial ownership in a company. See Kansas Energy 

LLC, Trademark Merchant Energy, LLC, 138 FERC ¶ 61,107, at P 28 (2012). Instead, 

 (continued...)
Docket No. RM14-14-000 167

some sellers include in their generation asset lists facilities in which they have claimed a 

relationship through only passive, non-controlling interests.

273. The Commission proposed the following clarifications with respect to the asset 

appendix: (1) a seller must enter the entire amount of a generator’s capacity (in MWs) 

in the “Capacity Rating (MW): Nameplate, Seasonal, or Five-Year Average” column of 

the generation list even if the seller only owns part of a facility; (2) a seller should list 

only one of the following as a “use” in the “Asset Name and Use” column of the 

transmission list: transmission, intrastate natural gas storage, intrastate natural gas 

transportation, or intrastate natural gas distribution; and (3) entities and generation assets 

in which passive ownership interests have been claimed should not be included in the 

horizontal market power indicative screens or reported in the appendix.359 

274. The Commission explained that if a seller does not believe that the entire capacity 

of a generation facility should be included in its indicative screens, it may explain its 

position in the transmittal letter filed with its horizontal market power screens, including 

letters of concurrence where appropriate,360 and thus account for only its portion of that 

 

sellers must account for generation capacity owned or controlled by the seller and its 

affiliates for purposes of analyzing horizontal market power. See id. P 37.

359 The Commission noted that sellers must demonstrate why such ownership 

interests should be deemed passive. NOPR, FERC Stats. & Regs. ¶ 32,702 at P 116 

n.129 (citing AES Creative Resources, L.P. et al., 129 FERC ¶ 61,239 (2009) (AES 

Creative)). 

360 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 187. 
Docket No. RM14-14-000 168

particular generation facility in the indicative screens. However, the entire capacity of 

the facility should be reflected in the list of generation assets in the appendix. 

275. The Commission noted that generating units within a single plant may be 

aggregated in a single row of the generation list if the information in the other columns 

is the same for all units, but separate plants cannot be aggregated into a single row. As 

discussed and adopted elsewhere in this Final Rule,361 the Commission proposed that 

qualifying facilities less than 20 MW may be aggregated by balancing authority area or 

market into one line in the generation asset list. The Commission further clarified that 

each asset should be listed only once; if it is owned by more than one affiliate, all

affiliate names should be included in the “Owned By” column. If a company or an 

affiliate is registered in the Commission’s company registration database,

362 the 

Commission proposed to clarify that the name in the asset appendix for that company 

must appear exactly the same as in the registration database.

276. With respect to the “Date Control Transferred” column in both the generation and 

transmission asset lists, the Commission proposed to clarify that the “Date Control 

 

361 See supra Section IV.C.2.c.

362 The term “company registration database” here refers to “FERC’s Online 

Company Registration application” (see http://www.ferc.gov/docsfiling/etariff/implementation-guide.pdf). However, Commission orders have referred to 

this database as we have also issued orders referring to it as “Company Registration,” 

(see Filing Via the Internet, Revisions to Company Registration and Establishing 

Technical Conference, 142 FERC ¶ 61,097 (2013)) or “Company Registration system” 

(see Filing Requirements for El. Utility S.A., Order Updating Electric Quarterly Report 

Data Dictionary, 146 FERC ¶ 61,169 (2014)).
Docket No. RM14-14-000 169

Transferred” column should identify the date on which a contract or other transaction 

that transfers control over a facility became effective. The Commission noted that

where appropriate, sellers may enter “N/A” in this field to indicate that it is not 

applicable to their asset(s) and explain why in the end note list.

277. With respect to the “Size” column in the list of transmission assets, the 

Commission proposed to clarify that the “Size” refers to both the length of the 

transmission line (i.e., feet or miles) and the capability of the line in voltage (kV). The 

Commission noted that sellers may aggregate their transmission assets by voltage. For 

instance, a seller that owns a transmission system with several hundred transmission 

lines might include two rows in the transmission asset list; one row with 200 miles of 

138 kV lines listed in the “Size” column and another row with 100 miles of 230 kV lines 

listed in the “Size” column as long as all the other columns (e.g., owned by, controlled 

by, balancing authority area, geographic region, etc.) remain the same for all assets 

aggregated in that row. The name for such aggregated facilities should describe the 

lines that are being aggregated, e.g., “230 kV transmission lines.”

i. Entire Amount of Generator’s Capacity in Asset 

Appendix

(a) Comments

278. Several commenters express concern over the Commission’s proposal to require a 

seller to include the entire amount of a generator’s capacity in its asset appendix, even if 
Docket No. RM14-14-000 170

the seller only owns part of a facility.

363

 Idaho Power, EEI, and FirstEnergy argue that 

this proposal may lead to double counting many generation facilities, or would 

otherwise lead to confusion.

364

 FirstEnergy also argues that the proposal will result in 

the amount of generation capacity reported by a seller in its asset appendix to differ from 

the amount of generation capacity reflected in its indicative screens, which may cause 

confusion over the amount of generation capacity controlled by the reporting entity.

365

 

NextEra adds that the information in the asset appendix may not match the information 

in the transmittal letter, which only includes a seller’s ownership interest in the 

generation facility where it has demonstrated its partial ownership (or lack of control 

over).366 Idaho Power, NextEra, and El Paso suggest that, if the Commission adopts this 

requirement, it should add a column to the asset appendix to allow a seller to declare the 

percentage of the generation facility it owns or controls.

367

 

 

363 See, e.g., Idaho Power at 2, 4; EEI at 17; FirstEnergy at 12-13; NextEra at 14-

15; El Paso at 4-5.

364 Idaho Power at 2, 4 (explaining that, if a seller enters the entire amount of the 

generator’s capacity when it owns just a share of the generating asset, it is unclear how 

the Commission would ensure that the generation capacity is not being counted twice); 

EEI at 17 (explaining that, if multiple sellers have an interest in an asset, and each lists 

the asset’s entire generation, the seller may over count the facility’s capacity); 

FirstEnergy at 12-13 (explaining that each joint owner including the entire generating 

capacity of a jointly owned facility may result in double-counting).

365 FirstEnergy at 12-13.

366 NextEra at 14.

367 Idaho Power at 2, 4; NextEra at 15 (expressing concern over the public having 

to search for the seller’s transmittal letter in which the seller declares its partial interest); 

 (continued...)
Docket No. RM14-14-000 171

(b) Commission Determination

279. We adopt the NOPR’s proposed clarification that a seller must enter the entire 

amount of a generator’s capacity in the generation asset list. In response to commenters’ 

concerns that the NOPR proposal could result in double counting, confusion, or other 

inconsistencies, we believe we have addressed those concerns through the addition of 

capacity rating and end notes columns discussed above. Specifically, as discussed more 

fully above, we are adopting Solomon/Arenchild’s proposal to add a new end notes 

column where sellers will be able to place explanatory notes.368 To the extent a seller is 

attributing to itself less than a facility’s full capacity rating, the seller can explain that in 

the end notes column. 

ii. Size Column in Transmission Asset List

(a) Comments

280. SoCal Edison questions the continued need for mileage of transmission assets as 

required in the asset appendix for entities that own integrated transmission networks 

rather than number of interconnection customer’s interconnection facilities. SoCal 

Edison argues that the total length in miles of a utility’s integrated network transmission 

assets has no meaningful relationship to the ability to exercise vertical market power. 

SoCal Edison further argues that one of the aims of the distributed generation movement 

 

El Paso at 4-5 (recommending that the Commission add a “Percentage of 

Ownership/Control” column to the asset appendix that would allow a seller to identify the 

percentage of a generation facility that the seller owns or controls). 

368 See supra Section IV.D.1.c.
Docket No. RM14-14-000 172

is to slow transmission growth, such that a lack of transmission system growth could 

merely reflect state preference for distributed generation over long-distance 

transmission. Finally, SoCal Edison argues that FERC Form No. 1 provides the 

Commission an annual update of the transmission mileage for major utilities and should 

prove sufficient for analysis. SoCal Edison recommends that the Commission explain 

the need to track mileage of transmission lines in service and how it relates to vertical 

market power, particularly in light of third parties’ ability to build new transmission 

additions under Order No. 1000.369

(b) Commission Determination

281. We disagree with SoCal Edison that reporting the mileage of transmission assets 

as required in the asset appendix for entities that own integrated transmission networks 

is unnecessary for a transmission market power analysis. While we agree that the total 

length in miles of a utility’s integrated network transmission assets has no direct 

relationship to the ability to exercise vertical market power, the asset appendix is not 

intended to provide a detailed study of a transmission owner’s system. Instead, the 

transmission asset list, like the generation asset list, provides a comprehensive list of the 

assets owned or controlled by a market-based rate seller and identifies the relevant 

 

369 Transmission Planning and Cost Allocation by Transmission Owning and

Operating Public Utilities, Order No. 1000, FERC Stats. & Regs. ¶ 31,323 (2011),

order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g, Order No. 1000-

B, 141 FERC ¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41

(D.C. Cir. 2014).
Docket No. RM14-14-000 173

transmission assets of sellers in wholesale power markets. Collecting this information 

adds transparency to the market and allows the public the opportunity to provide 

comments on a seller’s transmission assets. However, as noted in the NOPR, sellers are 

permitted to aggregate similar assets in a balancing authority area, which will reduce the 

burden associated with preparing the asset lists.370

iii. Passive Ownership

(a) Comments

282. Some commenters took issue with the Commission’s proposal to clarify that

entities and generation assets in which passive ownership interests have been claimed 

should not be reported in the asset appendix.371 EEI states that the clarification seems 

appropriate, but vague.372 EEI asks whether partial passive ownership by anyone is 

enough to exclude the asset from the asset appendix, or whether passive ownership as 

the seller’s only interest in the asset is what is required for that seller to exclude the asset 

from its asset appendix.

373

 

283. However, AAI cautions the Commission against eliminating the passive 

ownership interests reporting requirement. AAI argues that a passive interest can still 

affect competitive dynamics in the market because control is not the sole factor to 

 

370 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 118.

371 See, e.g., EEI at 17; AAI at 7-9.

372 EEI at 17.

373 Id.
Docket No. RM14-14-000 174

determine whether an entity exercises market power.374 AAI further argues that 

eliminating the reporting requirement could encourage generation owners to acquire 

undisclosed passive interests that enhance their incentive to engage in generation 

withholding and other abusive market behavior.375

(b) Commission Determination

284. We clarify that sellers should not include in their asset appendices entities and

facilities for which they have claimed, and demonstrated to the Commission, that the only 

relationship is through passive, non-controlling interests consistent with AES Creative

(i.e., where the seller has a strictly passive ownership interest in another entity, or another 

entity has a strictly passive ownership interest in the seller). This is consistent with 

current Commission practice. As noted in the NOPR, sellers must demonstrate why such 

a relationship should be deemed passive.376 We are not persuaded by AAI’s concerns 

that eliminating this reporting requirement could encourage generation owners to acquire 

undisclosed passive interests. We stress that we are not eliminating the requirement to 

demonstrate passivity; we are merely articulating our existing expectations. As noted 

above, we will continue to require that any seller that claims certain interests are passive 

or non-controlling must meet the standards set out in AES Creative.

 

374 AAI at 7-8.

375 Id. at 7-9

376 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 116 n.130 (citing AES Creative, 129 

FERC ¶ 61,239).
Docket No. RM14-14-000 175

iv. Other Issues

285. The Commission proposed clarifications regarding: populating the “Use” column 

in the transmission asset list; listing each asset once in an asset list; matching seller and 

affiliate names in the asset lists with the name registered in the Commission’s company 

registration database where possible; and the use of the “Date Control Transferred” 

column in the transmission asset list. 

(a) Comments

286. We did not receive any comments directly related to the aforementioned 

proposals. However, Solomon/Arenchild raised a concern related to clarifications 

regarding existing columns in the asset appendix. Solomon/Arenchild note that the 

proposed reporting of capacity values in generation asset list in the asset appendix may 

be inconsistent with the indicative screens. Specifically, Solomon/Arenchild state that 

there is a disconnect between the time period covered in the asset appendix and the time 

period covered in the indicative screens.377 Solomon/Arenchild also state that the 

indicative screens cannot rely solely on the ratings reported in the asset appendix 

because both summer and winter seasonal ratings typically are used in the indicative 

screens while the current asset appendix only allows sellers to report one rating per 

generation unit.378 Accordingly, Solomon/Arenchild recommend that the Commission 

specify that any generation sold or contracts terminated following the relevant study 

 

377 Solomon/Arenchild at 7-8.

378 Id.
Docket No. RM14-14-000 176

period be excluded from the historical study period of the triennial filing, and that any 

generation acquired or contracts begun since the historical study period be included in 

the indicative screens and asset appendix.

379

(b) Commission Determination

287. We adopt the proposed clarifications regarding: populating the “Use” column in 

the transmission asset list; listing each asset once in an asset list; matching seller and 

affiliate names in the asset lists with the name registered in the Commission’s company 

registration database where possible; and to the use of the “Date Control Transferred” 

column in the transmission asset list.

288. In regard to the “Date Control Transferred” column, we further clarify that sellers 

should identify the date on which a contract or other transaction that transfers control 

over a facility becomes effective. Where appropriate, companies may enter “N/A” in this 

field to indicate that it is not applicable to their asset(s) and provide any further 

explanation in the new end notes column.

289. We do not adopt Solomon/Arenchild’s recommendation to modify the data in the 

market power analysis to match the data required for the asset appendix. In Order No. 

697, the Commission stated “that when the Commission evaluates an application for 

market-based rate authority, the Commission’s focus is on whether the seller passes both 

 

379 Id. at Attachment 1 (noting that their recommendation conforms the indicative 

screens with the asset appendix that is part of the triennial filing, creates a “baseline” for 

any future notice of change in status filings, and more properly aligns the determination 

of when a change in status should be filed in the context of the 100 MW net change in 

capacity ownership for those entities that have sold generation or terminated contracts).
Docket No. RM14-14-000 177

of the indicative screens based on unadjusted historical data. Likewise, when a seller 

fails one or both of the screens and the Commission evaluates whether that seller passes 

the DPT, the Commission’s focus is on whether the seller passes the DPT based on 

unadjusted historical data”380 We will continue to require that a seller’s market power 

analysis rely on unadjusted historical data. To the extent that a seller’s generation assets 

have changed between the historical time period used in the market power analysis and 

the current time period of the asset appendix, the seller should explain and reconcile any 

differences in its application. Sellers may also provide sensitivity runs along with the 

required historical studies to show whether changed circumstances since the end of the 

study period justify a different conclusion than what the data from the study period 

indicates.381 The Commission has addressed the data disconnect issue by noting 

previously that the Commission will consider, on a case-by-case basis, clear and 

compelling evidence that seeks to demonstrate that certain changes in the market should 

be taken into account as part of the market power analysis in a particular case.382 

However, we provide the following guidance for preparing the studies and asset 

appendices for filings that commonly contain both asset appendices and market-power 

studies.

 

380 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 301.

381 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at PP 124-130.

382 Id. P 130.
Docket No. RM14-14-000 178

290. For initial applications where the seller has acquired an existing facility, sellers 

should prepare or rely on a study with historical data that transfers the MW values of the 

acquired generation from the Non-Affiliate Capacity rows to the Seller and Affiliate 

Capacity rows of their indicative screens and enter the information for the acquired 

facility in the generation asset list. 

291. For initial applications where the seller has newly built generation, sellers should 

submit a study that increases the total capacity value of the market/balancing authority 

area in which the seller is physically located by the seller’s newly built generation 

capacity. To accomplish this, the seller should use a previously approved study and add 

the value of their newly built generation to the total capacity value of the 

market/balancing authority area. Sellers must report this newly built generation in the 

generation asset list. 

292. In triennials, there are occasions when a seller’s generation fleet at the time of 

filing has changed since the close of the relevant study period. In these instances, sellers 

should explain the changes in the text of their filing, the end notes of the asset appendix if 

applicable, and if the changes are significant, the seller should provide a sensitivity 

analysis reflecting those changes. 

293. Notices of change in status generally do not require indicative screens. However, 

sometimes a seller provides screens for changes that the seller considers significant 

enough to merit the submission of screens to show that it would not fail the indicative 

screens with these new assets. In this case, we clarify that any studies submitted by a 
Docket No. RM14-14-000 179

seller should use the most recently available historical data for the market, but include the 

seller’s current generation portfolio, imports, and load and reserve obligations (if any). 

294. We understand Solomon/Arenchild’s concern that the indicative screens cannot 

solely rely on the ratings reported in the asset appendix. Based on our experience, sellers

that use seasonal ratings for thermal generation in their indicative screens are likely to use 

either summer or winter ratings in their asset appendix. However, in some cases sellers 

that use seasonal ratings in their screens use nameplate ratings in their asset appendix. 

Therefore, we clarify that when sellers use seasonal ratings in their indicative screens, 

their asset appendix should include the capacity rating used for each generation unit in 

their pivotal supplier screen(s). Requiring sellers to report the capacity rating used in 

their pivotal supplier screen eliminates this inconsistency and allows us to maintain the 

simplicity of the asset appendix. In addition, this ensures that the generation asset list 

displays the seasonal rating of each generation unit at the time of peak demand, when 

capacity is most needed.383 

4. Changes Regarding OATT Waiver and Citations in 

Transmission Asset List

a. Commission Proposal

295. The Commission has stated that even if a seller has been granted waiver of the 

requirement to file an OATT, those transmission facilities should be reported in its asset 

 

383 As previously noted, if a filing does not contain a market power study, or a 

particular generation asset is not included in a market power study, sellers should include 

in the asset appendix the rating that it used the last time the asset was included in a 

market power study.
Docket No. RM14-14-000 180

appendix,384 and the Commission stated in the NOPR that this should be reiterated and 

clarified going forward. Therefore, the Commission proposed to require any seller that 

has been granted waiver of the requirement to file an OATT for its facilities385 to report 

in its transmission asset list the citation to the Commission order granting the OATT 

waiver for those facilities. The Commission proposed to modify the example of the 

asset appendix found in Appendix B to Subpart H of Part 35 of the Commission’s 

regulations to add a new column in the transmission asset list for the citation to the 

Commission order accepting the OATT or granting waiver of the OATT requirement. 

Providing the citation to the Commission order accepting the OATT or granting waiver 

of the OATT requirement in the list of transmission assets was intended to facilitate the 

Commission’s and market participants’ verification that sellers were granted the 

appropriate authorizations or waivers.

b. Comments

296. While APPA/NRECA support the Commission’s proposal to require a seller that 

has been granted waiver of the requirement to file an OATT for its facilities to cite the 

Commission order granting that waiver in its list of transmission assets in the asset 

 

384 “We clarify that the transmission facilities that we require to be included in that 

asset appendix are limited to those the ownership or control of which would require an 

entity to have an OATT on file with the Commission (even if the Commission has 

waived the OATT requirement for a particular seller).” Order No. 697-A, FERC Stats. & 

Regs. ¶ 31,268 at P 378.

385 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 408.
Docket No. RM14-14-000 181

appendix,

386 other commenters oppose it. Some commenters note that the 

Commission’s proposal may be at odds with the Interconnection Customer 

Interconnection Facility (ICIF) rulemaking in Docket No. RM14-11-000 that was 

pending at the Commission at the time the comments were submitted.

387 SoCal Edison 

requests that the Commission reject this proposal because the new column will not 

provide useful information, in light of the proposed ICIF rulemaking, and may cause 

confusion.388 NextEra suggests that the Commission synthesize the OATT waiver 

provisions in both pending rulemakings.389

297. Other commenters argue that the proposal is unnecessary and unclear.390 

Specifically, FirstEnergy states that, if the citation to the OATT or OATT waiver is in 

the transmittal letter, including the citation in the asset appendix is redundant and 

unnecessary.

391

 FirstEnergy further states that, if a company transferred operational 

 

386 APPA/NRECA at 5; see also Golden Spread at 7.

387 SoCal Edison at 25 (explaining that the Commission is proposing a blanket 

waiver of all OATT, OASIS, and Standards of Conduct requirements to any public utility 

that is subject to such requirements solely because it owns, controls, or operates 

interconnection customer interconnection facilities and citing Open Access and Priority 

Rights on Interconnection Customer’s Interconnection Facilities, 147 FERC ¶ 61,123, at 

P 35 (2014)); NextEra at 15; EEI at 17-18.

388 SoCal Edison at 25.

389 NextEra at 15.

390 See, e.g., AEP at 9; EEI at 17; and FirstEnergy at 13. 

391 FirstEnergy at 13.
Docket No. RM14-14-000 182

control of its facilities to an RTO, a citation to the order authorizing the transfer should 

suffice.392 AEP argues that the proposal to provide a citation to the OATT waiver is an 

extra imposition on sellers that is inconsistent with the stated purpose of the NOPR.393

AEP and EEI state that OATTs are readily publicly available and therefore do not need 

to be included in the transmission asset list.394 AEP further argues that it is unclear 

which OATT waiver citation a company like AEP would list because its filings are 

frequently revised and updated.395 

c. Commission Determination

298. We adopt the proposal to require sellers to add a citation to the order accepting a 

seller’s OATT. Further, we agree with FirstEnergy’s suggestion that if a seller has 

transferred operational control of its facilities to an RTO/ISO, this cite should be to the 

order authorizing the transfer. Therefore, we have changed the text to the proposed

column (Column [B]) of the transmission asset list from “Cite to Order Accepting 

OATT or granting OATT waiver” to “Cite to order accepting OATT or order approving 

the transfer of transmission facilities to an RTO or ISO.” The change to remove 

“granting OATT waiver” is discussed below.

 

392 Id. at 14.

393 AEP at 9.

394 Id.; EEI at 17.

395 AEP at 9; see also EEI at 17.
Docket No. RM14-14-000 183

299. We do not agree with AEP’s assertion that this requirement is an extra imposition 

upon sellers. Further, in regard to AEP and EEI’s comments, we understand that OATT 

information is already publicly available. However, sellers are already required to 

supply this information as part of their demonstration that they meet the Commission’s 

vertical market power requirements. The new column provides a convenient location 

for sellers to provide the information and for the Commission or third-parties to find the 

information. We clarify that sellers are not expected to change the citation every time 

they revise or update their OATTs. Similar to Column [B] “Docket # where marketbased rate authority was granted” in the generation asset list, we expect sellers to 

provide citation to the initial order accepting a seller’s OATT or accepting the seller’s

transfer of transmission facilities to an RTO/ISO in Column [B] of the transmission 

asset list. This will minimize any burden associated with including this information in 

the transmission asset list.

300. However, we do not adopt the NOPR proposal to require sellers to add a citation 

to orders granting the seller waiver of the OATT requirements. We agree with SoCal 

Edison that this requirement will not provide useful information, in light of the Final 

Rule in the ICIF proceeding.396

 

396 See Open Access and Priority Rights on Interconnection Customer’s 

Interconnection Facilities, Order No. 807, FERC Stats. & Regs. ¶ 31,367 (2015)

(amending Commission regulations to waive the OATT requirements of section 35.28, 

the OASIS requirements of Part 37, and the Standards of Conduct requirements of Part 

358, under certain conditions, for entities that own interconnection facilities). 
Docket No. RM14-14-000 184

5. Electronic Format

a. Commission Proposal

301. Currently, virtually all of the asset appendices are submitted to the Commission 

using PDF format. Staff is unable to perform calculations on PDF files, or to search, or 

sort the data contained in the asset lists. Staff therefore frequently transfers the 

information included in the asset lists into spreadsheets for sorting, comparison 

purposes, and internal calculations, and in doing so has found numerous submission 

errors from sellers. In the NOPR, the Commission stated that if it provided a sample 

electronic spreadsheet and required sellers to submit the assets lists in an electronic 

spreadsheet, it would reduce filing burdens, improve accuracy, decrease the number of 

staff inquiries to sellers regarding submission errors, and result in a more efficient use of 

resources.

302. Therefore, the Commission proposed to require market-based rate sellers to submit

the Appendix B asset lists in an electronic spreadsheet format that can be searched, 

sorted, and otherwise accessed using electronic tools. The Commission proposed to post 

on the Commission’s website sample asset lists in formatted electronic spreadsheets and 

to require sellers to submit the asset appendix in the form and format of the sample 

electronic asset list spreadsheets.397

 

397 The Commission proposed that if a seller chooses to create its own workable

electronic spreadsheet, the file it submits must have the same format as the sample 

spreadsheet on the Commission website. Specifically, it must have the same exact 

columns and descriptive text as the sample spreadsheet. The Commission further 

proposed that the file must be submitted in one of the spreadsheet file formats accepted 

 (continued...)
Docket No. RM14-14-000 185

303. An example of the electronic spreadsheet for the asset appendix with the proposed 

new columns and column headings was included as Appendix B to the NOPR.

b. Comments

304. Commenters generally support the Commission’s proposal to require sellers to 

submit the asset appendix in an electronic spreadsheet format; however, several 

commenters request clarification or modification of the proposal.

398

 EPSA requests

clarification on the specific fields that would be required in the electronic format, and the

methodology that should be used to submit the electronic forms.399 E.ON urges the 

Commission to thoroughly vet the process to ensure ease of use and submission by 

market participants, which may require a public test period.400 EEI states that, “if the 

Commission simply intends to require market-based rate applicants and sellers to file the 

information in standard electronic formats, such as Adobe, Excel, and Word, that would 

be fine. Such straightforward electronic filing will simply mirror the current FERC 

eFiling process, which has eased the burden of filing documents at FERC. If, however, 

the Commission has in mind that market-based rate applicants and sellers must provide 

 

by the Commission for electronic filing. NOPR, FERC Stats. & Regs. ¶ 32,702 at P 63 

n.71. See FERC, Acceptable File Formats (January 2012), available at

http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp. 

398 See, e.g., APPA/NRECA at 5 (supporting the Commission’s proposal and 

requesting no clarifications or modifications); Solomon/Arenchild at 6-7; EPSA at 12; 

E.ON at 13, 14. 

399 EPSA at 12

400 E.ON at 13.
Docket No. RM14-14-000 186

the information using rigid new formats, e.g. with pre-defined rows and columns using 

XML data, EEI asks the Commission to engage in further dialogue with the regulated 

community first, to ensure that the format changes are reasonable, clear, and 

workable.”

401

c. Commission Determination

305. We adopt the NOPR proposal to require sellers to submit the asset appendix in an 

electronic spreadsheet format. 

306. EEI apparently misconstrued this proposal and we clarify here that the electronic 

format requirement for the asset appendix is specifically designed to stop the submission 

of asset appendices in Word or PDF format and instead require that these be submitted in 

a workable electronic file format such as Excel. We adopt the NOPR requirements of a 

“workable electronic spreadsheet,”402 provide an example on our website, and provide the 

 

401 EEI at 18.

402 “‘Workable electronic spreadsheet’ refers to a machine readable file with 

intact, working formulas as opposed to a scanned document such as an Adobe PDF file.” 

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 63 n.70. Additionally:

If a seller chooses to create its own workable electronic spreadsheet, the file 

it submits must have the same format as the sample spreadsheet on the 

Commission website. Specifically, it must have one worksheet for each of 

the indicative screens and each screen must have the same exact rows, 

columns, and descriptive text as the sample worksheets. Cells requiring 

negative values must be pre-programmed to only allow negative values. 

Likewise, cells with calculated values must contain a working formula that 

calculates the value for that cell. Finally, the file must be submitted in one 

 (continued...)
Docket No. RM14-14-000 187

electronic filing requirements for such a filing.403 Furthermore, we clarify that this 

requirement is not dependent upon any particular technology such as Extensible Markup 

Language (XML), and instead can use any one of a number of Commission accepted 

spreadsheet formats.404 In response to EPSA, we clarify that the entire asset appendix 

(including all relevant lists) should be submitted in the electronic format. Sellers should 

submit the electronic asset appendix as an attachment to their filings, following the 

Commission’s electronic filing requirements described above. 

307. Finally, we replace the example appendix found in Appendix B to Subpart H of 

Part 35 of the Commission’s regulations with the Appendix B in this Final Rule. 

6. Database

a. Commission Proposal

308. The Commission sought comment regarding whether in the future it would be 

beneficial to develop a comprehensive searchable public database of the information 

contained in the asset appendix, which would eventually replace the pre-formatted 

spreadsheet. The Commission noted that such an approach would allow market-based 

rate sellers to update their asset appendices when circumstances change. The 

 

of the spreadsheet file formats accepted by the Commission for electronic 

filing. See FERC, Acceptable File Formats (Jan. 2012), available at

http://www.ferc.gov/docs-filing/elibrary/accept-fileformats.asp.

NOPR, FERC Stats. & Regs. ¶ 32,702 at P 63 n.71.

403 Id. P 123 n.135.

404 Id. P 65 n.73; see also supra Section IV.A.4.c.
Docket No. RM14-14-000 188

Commission sought comments regarding whether such a database would be useful, how 

the database might be created, standardized and maintained, and the frequency with 

which it should be updated. The Commission further sought input on the usefulness of 

including unique identifiers for the affiliate companies and generation assets in such a 

database, e.g., the company registration database and the EIA Power Plant Code and 

Generator ID, respectively, where those identifiers exist. The Commission also sought

comment on the difficulty of reporting and the usefulness of including in such a database 

the percentage each affiliate owns of each of its assets.

b. Comments

309. While APPA/NRECA, Golden Spread, and E.ON support the Commission’s

proposal to develop a comprehensive, searchable public database of the information 

contained in the asset appendix,405 several other commenters expressed concern.

406

 

SoCal Edison and EEI argue that including contract data in the database would raise 

concerns about confidentiality.

407 EEI states that the database would need to be 

designed in close coordination with the regulated community to ensure a useful result, 

 

405 APPA/NRECA at 5; Golden Spread at 7; E.ON at 14 (stating that a database

would be particularly useful if the Commission ultimately adopts its proposal to redefine 

relevant markets for generation-only balancing authority areas, and it would provide 

market participants and market-based rate sellers with access to megawatt generation data 

needed for horizontal market power analyses).

406 See, e.g., SoCal Edison at 26; EEI at 18; Idaho Power at 2-3.

407 SoCal Edison at 26; EEI at 18 (adding that including contract data in the 

database would create additional information collection burdens and would also raise

concerns about the disclosure of Critical Energy Infrastructure Information (CEII)).
Docket No. RM14-14-000 189

minimize the regulatory burden, and address confidentiality and critical energy 

infrastructure information (CEII) concerns.408 Idaho Power states that, in some cases, 

proprietary information of a generator’s capacity would be masked in a public database, 

impacting the usefulness of the database.409 

310. Other commenters raise issues related to maintaining the database’s integrity.410 

SoCal Edison, EEI, and AEP state that the database could omit qualifying facilities’

generation and non-jurisdictional entities’ generation.411 SoCal Edison also argues that 

it would be difficult to assemble information from the asset appendix about long-term 

firm purchases into a meaningful database.412 Solomon/Arenchild support the database, 

in theory, but state that the database would require continual, time-consuming, and 

cumbersome maintenance to maintain its integrity.413 They further state that for such a 

database to provide meaningful information, one would need to be able to readily 

identify duplicates, overlaps etc., or the utility of the database will be undermined. 

NextEra echoes Solomon/Arenchild’s concern and state that the burdens associated with 

 

408 EEI at 18.

409 Idaho Power at 2-3.

410 See, e.g., SoCal Edison at 26; EEI at 18; AEP at 10; Solomon/Arenchild at 6-7; 

NextEra at 15; EPSA at 14.

411 SoCal Edison at 26 (adding also that the data may not be particularly useful due 

to joint ownership issues); EEI at 18; AEP at 10.

412 SoCal Ed. at 26.

413 Solomon/Arenchild at 6-7
Docket No. RM14-14-000 190

maintaining such a database would outweigh the benefits.414 EPSA expresses concern 

over whether the industry or the Commission will be responsible for updating the 

database and how the accuracy of the information will be ensured.

415

311. EPSA also seeks clarification on whether the database would eventually replace 

the asset appendix, or if both a database and an asset appendix would be required.416

EPSA states that, if both a database and an asset appendix will be required of all marketbased rate sellers, then such requirements would run counter to the Commission’s stated 

intentions to streamline the information required and reduce the regulatory burden on 

market-based rate sellers. EPSA suggests that, if sellers will be required to use the 

database for documentation of assets, the seller should be responsible for updating and 

maintaining its data on the database.417

312. AEP does not see the need for the Commission to host a comprehensive 

searchable public database, stating that the information is available through other means 

and creating the database would impose another reporting obligation on sellers.418

 

414 NextEra at 15.

415 EPSA at 14.

416 Id.

417 Id.

418 AEP at 9.
Docket No. RM14-14-000 191

c. Commission Determination

313. We will not direct the creation of a comprehensive public database as part of this 

rulemaking. In the NOPR, we sought industry comment on the usefulness of a potential 

database and for input on how the database might be created and maintained. While 

some commenters raise valid concerns about the structure, confidentiality, burden and 

maintenance of the database, others recognize the potential utility of a well-designed and 

properly administered database.419 Similarly, we continue to recognize the potential 

value of the database and may consider the creation of a database in the future. 

E. Category 1 and Category 2 Sellers

1. Commission Proposal

314. In Order No. 697, the Commission created a category of market-based rate 

sellers, Category 1 sellers, that are exempt from the requirement to periodically submit 

updated market power analyses in accordance with the regional reporting schedule. 

Category 1 sellers include wholesale power marketers and wholesale power producers 

that own or control 500 MW or less of generation in aggregate per region; that do not 

own, operate or control transmission facilities other than limited equipment necessary to 

connect individual generating facilities to the transmission grid (or have been granted 

waiver of the requirements of Order No. 888); that are not affiliated with anyone that 

owns, operates, or controls transmission facilities in the same region as the seller’s 

 

419 APPA/NRECA at 5; Golden Spread at 7; E.ON at 14; Solomon/Arenchild at 

6-7.
Docket No. RM14-14-000 192

generation assets; that are not affiliated with a franchised public utility in the same 

region as the seller’s generation assets; and that do not raise other vertical market power 

concerns.

420

 

315. In the NOPR, the Commission proposed to clarify the distinction in determining 

the seller category status of power marketers and power producers. For purposes of 

determining seller category status for each region, a power marketer should include all 

affiliated generation capacity in that region. Power producers only need to include

affiliated generation that is located in the same region as the power producer’s 

generation assets. The Commission explained that the reason behind this distinction is 

that a power marketer with no generation assets in the ground is assumed to have no 

home market; it is thus assumed to be equally likely to make sales in any region. In 

contrast, although a power producer has authorization to make sales in other regions, it 

is assumed that the majority of its sales will be in the region(s) in which it owns 

generation assets.

316. Thus, the Commission proposed to clarify that a power marketer with no 

generation assets may qualify as a Category 1 seller in any region where: (1) its affiliates 

own or control, in aggregate, 500 MW or less of generation capacity; (2) it is not 

affiliated with anyone that owns, operates or controls transmission facilities; (3) it is not 

affiliated with a franchised public utility; and (4) it does not raise other vertical market 

 

420 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 853-863; see also 18 CFR 

35.36(a)(2).
Docket No. RM14-14-000 193

power issues. The Commission noted that the above is consistent with the Commission’s

treatment of power marketers since the issuance of Order No. 697.

317. The Commission also proposed to clarify that a power producer may qualify as a 

Category 1 seller in any region in which the power producer itself owns generation and 

the power producer and its affiliates own or control, in aggregate, 500 MW of generation 

capacity or less, as long as the power producer is not affiliated with anyone that owns, 

operates or controls transmission facilities in that region, is not affiliated with a 

franchised public utility in that region, and does not raise other vertical market power 

issues. In addition, unlike power marketers, a power producer may qualify as a Category 

1 seller in a region where the power producer itself does not own or control any 

generation or transmission assets but where it has affiliates that are Category 2 sellers.

421

318. Therefore, the Commission proposed to revise the regulation at 18 CFR 

35.36(a)(2) and clarify that in order to qualify for Category 1 status, a seller must meet 

all of the requirements. Failure to satisfy any of these requirements results in a Category 

2 designation. 

2. Comments

319. EEI recommends that the Commission modify its proposed clarifications 

regarding Category 1 and Category 2 sellers. EEI encourages the Commission to allow 

 

421 The Commission noted that a mitigated seller cannot use an affiliated power 

producer in another region as a conduit to sell in a mitigated balancing authority area 

because all affiliates of a mitigated seller are prohibited from selling at market-based 

rates in any balancing authority area or market where the seller is mitigated. Order No. 

697-A, FERC Stats. & Regs. ¶ 31,268 at P 335.
Docket No. RM14-14-000 194

power marketers to demonstrate that their sales from particular capacity are confined to 

particular regions and thus should be counted accordingly in determining their category 

status.422 EEI adds that the Commission should modify the definition of a Category 1 

seller from “no more than 500 MW generation ownership and/or control” to “no more 

than 500 MW of uncommitted resources owned and/or controlled.”423 EEI contends that 

some companies have always had negative uncommitted resources because they are net 

buyers, and so should not be required to make updated market power analysis filings or 

change in status filings.424

3. Commission Determination

320. We adopt the proposed clarifications regarding Category 1 and Category 2 sellers 

and the corresponding regulatory changes to 18 CFR 35.36(a)(2) as proposed in the 

NOPR. 

321. In response to EEI’s comment to allow power marketers to demonstrate that sales 

from particular capacity are confined to a particular region, the Commission has found

that category seller status is based on the region in which generation capacity is owned or 

controlled by the seller and its affiliates in aggregate rather than where sales are made in 

an effort to keep the definition and demonstration of a seller’s category status simple and 

 

422 EEI at 19.

423 Id.

424 Id.
Docket No. RM14-14-000 195

straightforward.425 Since sales change frequently, we believe basing the category seller

status definition on sales could create an additional burden on sellers to demonstrate that 

their and their affiliates’ sales are confined to a particular region. However, we note that 

to the extent that any seller wishes to limit its market-based rate authority to a particular 

region or set of regions in its tariff, it is free to do so. If a seller does not have marketbased rate authority in a particular region, it will not have an obligation to file regular 

updated market-power analyses for that region. 

322. EEI also proposed that the category seller status designation be based on whether a 

seller owns or controls uncommitted resources in a region. We reject this proposal as 

beyond the scope of what was proposed in the NOPR. Moreover, the test for category 

seller status was intended to be a bright line test that would be easy to administer.426 The 

Commission has previously found that “aggregate capacity in a given region best meets 

our goal of ensuring that we do not create regulatory barriers to small sellers seeking to 

compete in the market while maintaining an ample degree of monitoring and oversight 

that such sellers do not obtain market power.”427 We do not believe that a seller with 

over 500 MW of capacity is the type of seller that the Commission intended to exclude 

from periodic updated market power analyses, regardless of whether the seller’s capacity 

happens to be committed at a particular point in time.

 

425 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 864-868.

426 Id. P 864.

427 Id. P 865; Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 360.
Docket No. RM14-14-000 196

F. Corporate Families

1. Corporate Organizational Charts

a. Commission Proposal

323. In the NOPR, the Commission proposed to require sellers to provide an 

organizational chart, in addition to the existing requirement428 to provide written 

descriptions of their affiliates and corporate structure or upstream ownership, for initial 

applications for market-based rate authority, updated market power analyses and notices 

of change in status reporting new affiliations.

324. The Commission noted that it has seen increasingly complex organizational 

structures as private equity funds and other financial institutions take ownership 

positions in generation and utilities.429 The Commission stated that requiring the filing 

of an organizational chart would make reviewing market-based rate filings more 

efficient, increase transparency, and synchronize information about corporate structure 

that the Commission receives from sellers with market-based rate authority with similar 

 

428 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 181, n.258 (also requiring 

sellers seeking market-based rate authority to describe the business activities of their 

owners, stating whether they are in any way involved in the energy industry).

429 We note that the Commission recently issued a NOPR seeking comment on a 

proposal to require each RTO and ISO to electronically deliver to the Commission data 

from market participants that lists market participants’ “connected entities,” including 

entities that have certain ownership, employment, debt or contractual relationships to the 

market participant, and describes the nature of such relationships. See Collection of 

Connected Entity Data from Regional Transmission Organizations and Independent 

System Operators, Docket No. RM15-23-000, 80 FR 58382 (Sept. 29, 2015), 152 FERC 

¶ 61,219 (2015).
Docket No. RM14-14-000 197

information that the Commission receives under section 203 of the FPA.

430 The 

Commission proposed to require that sellers provide an organizational chart similar to 

that which the Commission requires from section 203 applicants. Specifically, the 

Commission noted that section 33.2(c)(3) of its regulations431 provides that section 203 

applicants must include: a description of the applicant, including, among other things, 

organizational charts depicting the applicant’s current and proposed post-transaction 

corporate structures (including any pending authorized but not implemented changes) 

indicating all parent companies, energy subsidiaries and energy affiliates unless the 

applicant represents that the proposed transaction does not affect the corporate structure 

of any party to the transaction. The Commission proposed that market-based rate sellers 

be required to provide, in addition to the already required written descriptions of their 

affiliates and corporate structure or upstream ownership, an organizational chart 

depicting the market-based rate seller’s current corporate structures (including any 

pending authorized but not implemented changes) indicating all upstream owners, 

energy subsidiaries and energy affiliates. The Commission believed that the increased 

burden on market-based rate sellers would be minimal as most sellers have this 

organizational chart available.

325. Thus, the Commission proposed to revise the text in section 35.37(a)(2) of the 

Commission’s regulations to add this requirement for purposes of initial applications 

 

430 16 U.S.C. 824b.

431 See 18 CFR 33.2(c)(3).
Docket No. RM14-14-000 198

and updated market power analyses. The Commission also proposed that such 

organizational chart be required for any notice of change in status involving a change in 

the ownership structure that was in place the last time the seller made a market-based 

rate filing with the Commission. Therefore, the Commission proposed to revise the text 

in section 35.42(c) accordingly.

b. Comments

326. Many commenters oppose the Commission’s proposal to require sellers to 

provide an organizational chart, in addition to written descriptions of their affiliates and 

corporate structure or upstream ownership, for initial applications for market-based rate 

authority, updated market power analyses, and notices of change in status reporting new 

affiliations.432 However, APPA/NRECA and Golden Spread support the proposal.433

327. Several commenters submit that this proposal would impose a burden on sellers 

disproportionate to any benefit received, requiring significant investigation into 

numerous affiliate relationships.434 EPSA notes that, even if a market-based rate entity 

already has an organizational chart, often those charts are not developed and used for the 

purpose of showing control, but rather to demonstrate how finances flow throughout the 

 

432 See, e.g., EPSA at 15-17; E.ON at 14-16; NextEra at 16; EEI at 19; FirstEnergy 

at 14-16; NRG Companies at 3-6; AEP at 9.

433 APPA/NRECA at 5; Golden Spread at 7.

434 See, e.g., EPSA at 15-17 (noting that not all market-based rate sellers have 

these organization charts readily available and that many sellers have hundreds of 

affiliates); E.ON at 14-15; NextEra at 16; EEI at 19; NRG Companies at 3-4; AEP at 9.
Docket No. RM14-14-000 199

various companies.435 Consequently, EPSA argues that the charts would require 

significant revisions to comply with the Commission’s proposal.436

328. EPSA proposes that, if the Commission implements the proposal, the 

Commission should limit the entities depicted in the organizational chart to include only 

public utilities subject to the Commission’s jurisdiction rather than all affiliates within a 

seller’s corporate structure.437 Other commenters state that the Commission does not 

need an organizational chart to evaluate market power concerns and that an 

organizational chart does not provide meaningfully different or material information to 

the Commission than is currently required.438 Specifically, FirstEnergy argues that, 

because the evaluation of a market-based rate application treats the seller and its 

affiliates as a single entity, the complex internal relationships among affiliated entities 

that might be illustrated in an updated organizational chart are not relevant to the 

Commission’s evaluation of whether an entity should enjoy market-base rate 

authority.439

 

435 EPSA at 16.

436 Id.

437 Id. at 15-16.

438 See, e.g., E.ON at 15-16; NextEra at 16; EEI at 19; FirstEnergy at 14-16; NRG 

Companies at 5.

439 FirstEnergy at 15.
Docket No. RM14-14-000 200

329. If the Commission adopts this proposal, some commenters suggest that the 

Commission provide further guidance regarding which affiliated entities should be 

included in the organizational chart.

440

 E.ON requests that the Commission clarify the 

meaning of “energy affiliate” and “energy subsidiary” and suggests that the meaning be 

limited to affiliates and subsidiaries that (1) own or control electric generation or inputs 

to electric power production in the relevant market or balancing authority area; (2) own, 

operate, or control electric transmission facilities in the relevant market or balancing 

authority area; or (3) have a franchised service territory in the relevant market or 

balancing authority area.441 EPSA requests clarification of how the Commission would 

treat sellers that are part of joint ventures, whether they would be exempt from the 

organizational chart or require particular treatment in the organizational chart.442

330. Some commenters assert that if the Commission adopts this proposal, the 

Commission should allow exemptions for specific filers.443 AEP notes that Order No. 

717 eliminated a similar previous requirement for transmission providers to post an 

organizational chart of all affiliates, finding such a requirement to be an “undue burden 

 

440 E.ON at 15; EPSA at 16. 

441 E.ON at 15.

442 EPSA at 16.

443 See, e.g., AEP at 19; EEI at 19; FirstEnergy at 15-16.
Docket No. RM14-14-000 201

on transmission providers.”444 AEP also suggests that only filings that impact the 

organizational structure should require an organizational chart.445 EEI similarly 

proposes that an organizational chart should not be required if “that applicant 

demonstrates that the proposed transaction does not affect the corporate structure of any 

party to the transaction.”446 FirstEnergy suggests that there should be no need for a 

seller to submit an organizational chart (1) if the seller and its affiliates operate within an 

RTO with Commission-approved market monitoring and mitigation procedures and rely 

on such procedures to address horizontal market power concerns or (2) if a seller has 

become affiliated with a new entity that owns generation or transmission assets and 

where the transaction has been approved by the Commission pursuant to its authority 

under section 203 of the FPA.447

331. If the Commission adopts the organizational chart proposal, some commenters 

suggest that the Commission allow flexibility for meeting this proposal.448 The NRG 

Companies suggest that the Commission allow sellers to submit simplified 

 

444 AEP at 9 (citing Standards of Conduct for Transmission Providers, Order No. 

717, FERC Stats. & Regs. ¶ 31,280, at P 243 (2008)).

445 Id.

446 EEI at 19.

447 FirstEnergy at 15-16 (arguing that the requirement should be limited to 

circumstances in which the information may be useful to its review of an application for 

market-based rate authority).

448 NRG Companies at 5; AEP at 10.
Docket No. RM14-14-000 202

organizational charts that omit intermediate holding companies, energy subsidiaries and 

affiliates not relevant to the analysis in the applicable filings.449 AEP proposes that 

market-based rate sellers be allowed to provide a link to an organizational chart on their 

websites or other accessible location.450 

c. Commission Determination

332. We adopt the corporate organizational chart requirement with modifications and 

clarifications, as discussed below. We disagree with commenters’ concerns that filing 

such charts will impose an undue burden on sellers. The Commission already requires 

sellers to file organizational charts for filings under FPA section 203, and, as EPSA 

notes, some companies already have organizational charts for other purposes. 

Furthermore, as acknowledged by some commenters, the information that the 

Commission would require in organizational charts does not materially differ from what 

is currently provided in narrative form in market-based rate filings. Thus, presenting 

this same information in a graphic format should not be unduly burdensome. Similarly, 

presenting organizational charts in market-based rate filings, rather than through links to 

a corporate website as proposed by AEP, should not be unduly burdensome.

333. However, in response to commenters’ concerns, we provide further guidance 

regarding the extent to which upstream owners and affiliates need to be included in the 

corporate organizational charts. First, we find that the terms “energy subsidiaries” and 

 

449 NRG Companies at 5.

450 AEP at 10.
Docket No. RM14-14-000 203

“energy affiliates,” as used in the FPA section 203 context and as originally proposed in 

the NOPR, are not meaningful in the market-based rate context. Instead, we clarify that 

instead of “indicating all upstream owners, energy subsidiaries, and energy affiliates” in 

the organizational chart, as proposed in the NOPR, filers should indicate all affiliates, as 

defined under section 35.36(a)(9) of the Commission’s market-based rate regulations. 

Second, to minimize burdens on filers and to simplify the charts, we clarify that if an 

entity is owned by multiple individual investors, such investors may be grouped in the 

organizational chart as long as they are identified elsewhere in the filing.

334. We caution applicants to examine all upstream ownership information to ensure 

that all affiliates are captured in the chart. Applicants should not assume that upstream 

owners are not affiliates of the applicant without looking further up the ownership chain. 

For example, suppose the applicant (Company A) has four upstream owners (Companies 

B, C, D, and E) each of which owns 8 percent of the voting shares of A. If Company F 

owns 100 percent of the voting interests in Companies B, C, D, and E, under the 

Commission’s affiliate definition, Company F indirectly owns 32 percent of Company A 

and should be listed in the chart as an affiliate of Company A. Furthermore, since 

Companies A, B, C, D, and E are all under the common control of Company F, 

Companies B, C, D, and E also are affiliated with Company A under the Commission’s 

definition and should be depicted as such in the organizational chart, even though they 

own less than 10 percent of the voting interests in Company A. Further, as the 

Commission clarified in Tonopah Solar Energy, LLC, applicants are not permitted to use 
Docket No. RM14-14-000 204

a derivative share method to calculate ownership interests in downstream partiallyowned entities for purposes of identifying affiliates.

451

335. Consistent with our clarifications above, we will revise the regulatory text in 

35.37(a)(2) to clarify that the organizational chart must include affiliates, without any 

further reference to “upstream owners,” “energy subsidiaries,” or “energy affiliates.” 

We will also revise the regulatory text in section 35.42(c) of the Commission’s 

regulations to require the submission of an organizational chart that depicts the seller’s 

prior and new affiliations unless the change in status does not affect the seller’s 

affiliations.

2. Single Corporate Tariff

a. Commission Proposal

336. In the NOPR, the Commission noted that when a corporate family has more than 

one affiliated seller, it may use a joint tariff. The Commission committed to clarify on 

its website how a corporate family that chooses to submit a joint master corporate tariff 

should identify its designated filer and what each of the other filers should submit into 

their respective eTariff databases. This information can be found on the Commission’s 

website at http://www.ferc.gov/industries/electric/gen-info/mbr/tariff/joint.asp.

b. Comments

337. EEI appreciates the Commission’s recognition that allowing joint filings for 

corporate families provides economy of effort to companies.452 EEI encourages the 

 

451 Tonopah Solar Energy, LLC, 151 FERC ¶ 61,203, at PP 11-12 (2015).
Docket No. RM14-14-000 205

Commission to continue working with companies to enable companies to file joint tariffs 

within their corporate families.453 

c. Commission Determination

338. There is no opposition to the Commission’s NOPR clarification. We reiterate 

that when a corporate family has more than one affiliated seller, it may use a joint 

master tariff. Filing instructions for entities wishing to use a joint tariff are available on 

the Commission’s website, as stated above.

G. Part 101 and 141 Waivers

1. Commission Proposal

339. In the NOPR, the Commission noted that it has granted certain entities with 

market-based rate authority, such as power marketers and independent power producers, 

waiver of the Commission Uniform System of Accounts requirements, specifically Parts 

41, 101, and 141 of the Commission’s regulations, except sections 141.14 and 141.15. 

The Commission clarified that any waiver of Part 101 granted to a market-based rate 

seller is limited such that the waiver of the provisions of Part 101 that apply to 

hydropower licensees is not granted with respect to licensed hydropower projects. The 

Commission stated that hydropower licensees are required to comply with the 

requirements of the Uniform System of Accounts pursuant to 18 CFR Part 101 to the 

extent necessary to carry out their responsibilities under Part I of the FPA, particularly 

 

452 EEI at 20.

453 Id.
Docket No. RM14-14-000 206

sections 4(b), 10(d) and 14 of the FPA.454 The Commission further noted that a 

licensee’s status as a market-based rate seller under Part II of the FPA does not exempt it 

from accounting responsibilities as a licensee under Part I of the FPA.455 Thus, 

hydropower licensees that received waiver of Part 101 of the Commission’s regulations 

as part of their market-based rate applications under Part II of the FPA are cautioned that 

such waivers do not relieve them of their obligations to comply with the Uniform System 

of Accounts to the extent necessary to carry out their responsibilities under Part I of the 

FPA with respect to their licensed projects.

340. The Commission further directed market-based rate sellers that own licensed 

hydropower projects to ensure that their market-based rate tariffs reflect appropriate 

 

454 In Trafalgar Power Inc., 87 FERC ¶ 61,207, at 61,798 n.46 (1999) (Trafalgar 

Power), the Commission stated: 

Under [s]ection 14 of the FPA, the Federal government may take over a project 

upon expiration of the project’s licensee, conditioned upon the government’s 

payment to the licensee of the ‘net investment of the licensee in the project or 

projects taken.’ Section 4(b) requires licensees to file a statement showing the 

‘actual legitimate original cost of construction of such project’ to enable the 

Commission to determine ‘the actual legitimate cost of and the net investment in’ 

the project. Section 10(d) requires licensees to establish an amortization reserve 

account that will reflect excess or surplus earnings of their licensed project if such 

earnings have accumulated in excess of a reasonable rate of return upon the ‘net 

investment’ in the project during a period beginning after the first twenty years of 

operations. Pursuant to [s]ection 10 (d) of the FPA the amount transferred to the 

amortization reserve may be used to reduce a licensee’s net investment in the 

project, and if, after expiration of the license, the government takes over the 

project under [s]ection 14, it will be required to compensate the licensee for its net 

investment in the project, reduced by the amortization reserve for the project.

455 See Seneca Gen., LLC et al., 145 FERC ¶ 61,096, at P 23 n.20 (2013) (Seneca 

Gen) (citing Trafalgar Power, 87 FERC at 61,798).
Docket No. RM14-14-000 207

limitations on any waivers that previously have been granted. Specifically, to the extent 

that the hydropower licensee has been granted waiver of Part 101 as part of its marketbased rate authority, the licensee’s market-based rate tariff limitations and exemptions 

section should be revised to provide that the seller has been granted waiver of Part 101 of 

the Commission’s regulations with the exception that waiver of the provisions that apply 

to hydropower licensees has not been granted with respect to licensed hydropower 

projects. Similarly, to the extent that a hydropower licensee has been granted waiver of 

Part 141 as part of its market-based rate authority, it should ensure that the limitation and 

exemptions section of its market-based rate tariff specifies that waiver of Part 141 has 

been granted, with the exception of sections 141.14 and 141.15 (which pertain to the 

filing by hydropower licensees of Form No. 80, Licensed Hydropower Development 

Recreation Report, and the Annual Conveyance Report).456

341. The Commission stated that these market-based rate tariff compliance filings are 

to be made the next time the hydropower licensee proposes a change to its market-based 

rate tariff, files a notice of change in status pursuant to 18 CFR 35.42, or submits an 

updated market power analysis in accordance with 18 CFR 35.37. In addition, going 

forward, any market-based rate seller requesting waivers of Parts 101 and/or 141 should 

include these limitations in their market-based rate tariffs, regardless of whether they own 

any licensed hydropower projects. This will ensure that hydropower licensees understand 

 

456 See Domtar Maine, LLC, 133 FERC ¶ 61,207, at P 23 (2010).
Docket No. RM14-14-000 208

the limitations on Parts 101 and 141 waivers. To the extent that the market-based rate 

seller is not a licensee, these limitations should not have any effect as they only deny 

waiver of certain provisions affecting licensees. If a market-based rate seller becomes a 

hydropower licensee after it receives market-based rate authority, it must file revisions to 

its market-based rate tariff to reflect the limitations in its Parts 101 and 141 waivers 

within 30 days of the effective date of its license.

2. Comments

342. Some commenters oppose the Commission’s clarification that hydropower 

licensees are required to comply with the requirements of the Uniform System of 

Accounts pursuant to 18 CFR Part 101 to the extent necessary to carry out their 

responsibilities under Part I of the FPA.457 They submit that the Commission in Order 

No. 697 decided against repealing waivers of the accounting requirements given to 

certain market-based rate entities, finding that “little purpose would be served to require 

compliance with accounting regulations for entities that do not sell at cost-based rates and 

do not have captive customers.”458 In addition, they assert that hydropower licensees 

with market-based rate authorizations neither sell at cost-based rates nor have captive 

customers.

 

457 EPSA at 17-18; NHA at 2-10; EEI at 21-22. But see APPA/NRECA at 5; 

Golden Spread at 7.

458 See, e.g., EPSA at 18 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 

P 985).
Docket No. RM14-14-000 209

343. Further, these commenters contend that requiring licensees to bring their accounts 

into conformance with the Uniform System of Accounts is not only unnecessary, but also 

would be costly and burdensome, require substantial work, and impose potential costs 

associated with hiring new accounting personnel, while yielding no identified benefit. 

According to commenters, hydropower licensees can already satisfy the statutory 

requirements in FPA Part I by employing Generally Applicable Accounting Principles.

344. National Hydropower Association (NHA) contends that the regulatory burden 

imposed on hydropower licensees to conform to the Uniform System of Accounts is 

disproportionate to the concern underlying the Commission’s clarification of hydropower 

licensees’ responsibilities, particularly sections 4(b), 10(d), and 14 of the FPA. 

According to NHA, the calculation of net investment and amortization reserves only 

becomes relevant in case of a federal takeover of the project under section 14 of the FPA 

and during relicensing, if the project is awarded to a competing applicant.459 Further, 

NHA argues that there has not been a federal takeover of a licensed hydroelectric project 

and the Commission has yet to issue a new license to a competing applicant since the 

enactment of the FPA. Accordingly, NHA argues that the remote likelihood that a 

licensee will be paid its “net investment” for a project should allow licensees flexibility 

when complying with the FPA Part I statutory provisions identified in the NOPR.460

 

459 NHA at 6 (citing 16 U.S.C. §§ 807(a); 808(a)(1)).

460 Id. at 7-8.
Docket No. RM14-14-000 210

Additionally, NHA argues that, in similar circumstances where the Commission 

addressed the FPA compliance obligations in light of an evolving electric industry, the 

Commission chose to eliminate a regulatory burden.461 Therefore, NHA asserts that since 

hydropower licensees can rely on Generally Accepted Accounting Principles to comply 

with applicable provisions of FPA Part I, the Commission’s concerns regarding the FPA 

Part I provisions would not be implicated by allowing hydropower licensees to use 

Generally Accepted Accounting Principles to fulfill their statutory obligations. Thus, 

commenters ask the Commission to find that hydropower licensees can meet FPA Part I 

statutory requirements if they follow Generally Accepted Accounting Principles. 

However, if the Commission determines that licensees must comply with Part 101 in 

order to fulfill their statutory obligations under FPA Part I, then commenters request that 

the Commission: (1) provide guidance regarding which requirements of Part 101 it 

considers necessary to comply with FPA Part I;462 (2) only apply this policy 

prospectively;463 and (3) delay implementation of this policy for at least one year to 

provide sufficient time to allow affected licensees to bring their accounting ledgers into 

compliance.464 Regarding which specific accounts the Commission would expect 

 

461 Id. at 8 (citing Payment of Dividends From Funds Included in Capital Account, 

148 FERC ¶ 61,020 (2014)).

462 EEI at 22; EPSA at 18; NHA at 8-9.

463 EEI at 22; EPSA at 18; NHA at 8-9.

464 EEI at 22; NHA at 8-9.
Docket No. RM14-14-000 211

licensees to maintain, NHA and EEI state the Commission should limit the number of 

accounts it deems necessary for a hydropower licensee to carry out its responsibilities 

under FPA Part I in order to minimize cost and burden for companies.465

3. Commission Determination

345. We affirm the NOPR clarification that any waiver of Part 101 granted to a 

market-based rate seller is limited such that the waiver of the provisions of Part 101 that 

apply to hydropower licensees is not granted with respect to Commission-licensed 

hydropower projects. We recognize that in Order No. 697, the Commission concluded 

that “the costs of complying with the Commission’s [Uniform System of Accounts] 

requirements and, specifically Parts 41, 101, and 141 of the Commission’s regulations, 

outweigh any incremental benefits of such compliance where the seller only transacts at 

market-based rates.”466 However, a licensee’s status as a market-based rate seller under 

Part II of the FPA does not exempt it from accounting responsibilities as a hydropower 

licensee under Part I of the FPA.467 Thus, while hydropower licensees may have 

received waiver of Part 101 of the Commission’s regulations as part of their marketbased rate authorizations under Part II of the FPA, that waiver does not relieve them of 

their obligations to comply with the Uniform System of Accounts to the extent 

 

465 EEI at 22: NHA at 9.

466 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 985.

467 See Seneca Gen., 145 FERC ¶ 61,096 at P 23 n.20 (citing Trafalgar Power, 87 

FERC at 61,798).
Docket No. RM14-14-000 212

necessary to carry out their responsibilities under Part I of the FPA with respect to their 

licensed projects. Moreover, we note that such responsibilities to maintain the

information required for compliance with Part 101 existed prior to the establishment of 

the Commission’s market-based rate program.

346. Regarding comments that the Commission’s clarification is not only unnecessary, 

but also would be costly and burdensome, require substantial work, and impose potential 

costs associated with hiring new accounting personnel, while yielding no identified 

benefit, we disagree. We find that use of Generally Accepted Accounting Principles 

will not satisfy the statutory requirements under FPA sections 4(b),468 14,469 and 

10(d).470 Further, although NHA contends that the chances are remote that the United 

States federal government would take over a hydropower project under FPA section 14, 

the chance still exists. Under Part 101 of the Commission’s regulations, licensed 

hydropower projects are required to maintain records that may be used to calculate net 

investment in the event that the Commission recommends that the United States federal 

government take over a hydropower project under FPA section 14 (or another entity 

takes over the license pursuant to FPA section 15). Thus, there is a need for licensees to 

 

468 16 U.S.C. § 797(b) (relating to determining actual legitimate original cost of 

and net investment in a licensed project).

469 16 U.S.C. § 807 (regarding the right of the Federal government to take over a 

project by paying the licensee its net investment).

470 16 U.S.C. § 803(d) (relating to surplus accumulated in excess of a specified 

reasonable rate of return and requirement to maintain amortization reserves that may be 

applied from time to time to reduce net investment).
Docket No. RM14-14-000 213

maintain adequate books and records in case either of those situations occur. However, 

we will attempt to minimize the burden of compliance as discussed below. 

347. We find that a hydropower licensee that sells only at market-based rates may 

meet its obligations to comply with the Uniform System of Accounts by following 

General Instruction No. 16 under Part 101 of the Commission’s regulations.471 

Accordingly, we clarify that hydropower licensees that make sales only at market-based 

rates and that have been granted Commission waiver of Part 101 as part of their marketbased rate tariffs may satisfy the requirements in Part 101 of the Commission’s 

regulations by following General Instruction No. 16 under Part 101. We find that doing 

so will not be unduly burdensome. However, we further clarify that hydropower 

licensees that have a cost-based rate tariff on file with the Commission are still required 

to comply with the full requirements of FPA sections 4(b), 10(d), and 14 and the 

amortization reserve article in their licenses. 

348. We deny commenters’ request that the Commission implement these 

clarifications prospectively and delay the implementation for at least one year to provide 

sufficient time to allow affected licensees to bring their accounting ledgers into 

compliance. We find it is not unduly burdensome for a hydropower licensee that sells 

only at market-based rates to meet its longstanding obligation to comply with the 

 

471 18 CFR pt. 101 (General Instruction No. 16).
Docket No. RM14-14-000 214

Uniform System of Accounts by following General Instruction No. 16 under Part 101 of 

the Commission’s regulations. 

349. Accordingly, as discussed in the NOPR, we will direct market-based rate sellers 

that own licensed hydropower projects to ensure that their market-based rate tariffs 

reflect appropriate limitations on any waivers that previously have been granted. 

Specifically, to the extent that the hydropower licensee has been granted waiver of Part 

101 as part of its market-based rate authority, the licensee’s market-based rate tariff 

limitations and exemptions section should be revised to provide that the seller has been 

granted waiver of Part 101 of the Commission’s regulations with the exception that 

waiver of the provisions that apply to hydropower licensees has not been granted with 

respect to licensed hydropower projects. Similarly, to the extent that a hydropower 

licensee has been granted waiver of Part 141 as part of its market-based rate authority, it 

should ensure that the limitation and exemptions section of its market-based rate tariff 

specifies that waiver of Part 141 has been granted, with the exception of sections 141.14 

and 141.15 (which pertain to the filing by hydropower licensees of Form No. 80, 

Licensed Hydropower Development Recreation Report, and the Annual Conveyance 

Report).472 As explained in the NOPR, these market-based rate tariff compliance filings 

are to be made the next time the hydropower licensee proposes a change to its marketbased rate tariff, files a notice of change in status pursuant to 18 CFR 35.42, or submits 

 

472 See Domtar Maine, LLC, 133 FERC ¶ 61,207 at P 23.
Docket No. RM14-14-000 215

an updated market power analysis in accordance with 18 CFR 35.37. In addition, going 

forward, any market-based rate seller requesting waivers of Parts 101 and/or 141 should 

include these limitations in its market-based rate tariffs, regardless of whether it owns any 

licensed hydropower projects. This will ensure that hydropower licensees understand the 

limitations on Parts 101 and 141 waivers. To the extent that the market-based rate seller 

is not a licensee, these limitations should not have any effect as they only deny waiver of 

certain provisions affecting licensees. 

350. If an existing market-based rate seller becomes a hydropower licensee and the 

Commission previously accepted the seller’s market-based rate tariff with full waivers 

without the limitations relating to hydropower licensees discussed herein, the seller must 

file revisions to its market-based rate tariff to reflect the limitations in its Parts 101 and 

141 waivers within 30 days of the effective date of its hydropower license.

H. Miscellaneous Issues

1. Regional Reporting Schedule

a. Commission Proposal

351. In the NOPR, the Commission noted that that section 35.37(a)(1) of the

Commission’s regulations requires Category 2 sellers to submit a market power analysis 

according to the regional schedule contained in Order No. 697. The Commission 

proposed to revise section 35.37(a)(1) so that instead of referring to the schedule 

contained in Order No. 697, section 35.37(a)(1) would to refer to an updated regional 
Docket No. RM14-14-000 216

reporting schedule posted on the Commission’s website.473 The Commission noted that 

the revised regional reporting schedule and associated map may be found on the 

Commission’s website at http://www.ferc.gov/industries/electric/geninfo/mbr/triennial/when.asp.

b. Comments

352. EEI encourages the Commission to confer with the regulated community before 

making changes in the schedule and map, to ensure that those changes are workable and 

appropriate.474 Additionally, EEI states that one significant step that the Commission 

could undertake to reduce the burden on Category 2 sellers would be to extend the time 

frame for submitting updated analyses from every three years to every four to five years. 

EEI states that the Commission would continue to receive change in status filings as 

needed in the interim that would alert the Commission of changes occurring in a given 

market that might raise potential market power concerns, and if the Commission is 

concerned about those changes, the Commission already has the right to ask for more 

information or even an updated market power analysis from the seller filing the change 

in status report.475

 

473 The NOPR also included an updated region map in Appendix D.

474 EEI at 22.

475 Id. at 23.
Docket No. RM14-14-000 217

c. Commission Determination

353. We adopt the NOPR’s proposal to revise section 35.37(a)(1) of the Commission’s 

regulations with regard to the regional reporting schedule. The regional reporting 

schedule and associated map can be found on the Commission’s website.

476

 In response 

to EEI’s request that the Commission confer with the regulated community before 

making changes to the regional reporting schedule, we clarify that we are not changing 

the regional reporting schedule; we simply are changing the regulation to refer to the upto-date schedule posted on the Commission’s website. Our intention is to make the 

reporting schedule more transparent and accessible. We do not adopt EEI’s suggestion to

extend the time frame for submitting updated market power analyses from every three 

years to every four to five years. This suggestion is outside the scope of the NOPR. In 

any event, we believe that three years is a reasonable reporting schedule for filing 

updated market power analyses. EEI contends that sellers would submit change in status 

filings in the interim period. But change in status filings, while important, often lack the 

level of detail provided in updated market power analyses, such as indicative screens or 

SIL studies. Finally, in response to EEI’s request that the Commission confer with the 

regulated community before making changes to the regional reporting schedule, we note 

that the region map is reflective of circumstances (such as mergers) that already have 

 

476 The regional reporting schedule and region map can be found on the 

Commission’s website at http://www.ferc.gov/industries/electric/geninfo/mbr/triennial/when.asp. Additionally, we include the regional reporting schedule in 

Appendix C of this Final Rule and the region map in Appendix D of this Final Rule. 
Docket No. RM14-14-000 218

taken place. Future changes to the map would occur if, for example, a seller moved from 

an RTO in one region to an RTO in another region.

2. Affirmative Statement

a. Commission Proposal

354. In the NOPR, the Commission noted that in Order No. 697, as part of the vertical 

market power analysis, the Commission stated that it would require sellers to make an 

affirmative statement that they have not erected barriers to entry into the relevant market 

and will not erect barriers to entry into the relevant market. The Commission further 

noted that the requirement is codified at section 35.37(e)(4). The Commission explained 

that although the Commission stated in Order No. 697 that the obligation applies both to 

the seller and its affiliates,477 many sellers have not mentioned their affiliates when

making their affirmative statements. Therefore, the Commission proposed to revise 

section 35.37(e)(4) (which was proposed elsewhere in the NOPR to be renumbered as 

section 35.37(e)(3)) to make clear that the affirmative statement requirement applies to 

the seller and its affiliates.

b. Comments

355. APPA/NRECA and Golden Spread support clarifying that an applicant for marketbased rate authority must affirmatively state, on behalf of itself and its affiliates, that they 

have not and will not erect barriers to entry in the relevant market(s).478

 

477 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 447.

478 APPA/NRECA at 5; Golden Spread at 7.
Docket No. RM14-14-000 219

c. Commission Determination

356. We adopt the proposal in the NOPR concerning the affirmative statement. No 

adverse comments were filed with respect to this proposal. As noted above, this 

obligation already applies both to the seller and its affiliates. However, because many 

sellers have not mentioned their affiliates when making their affirmative statements, we 

adopt the proposal to revise the regulations to make it clear that the affirmative statement 

requirement applies to the seller and its affiliates. The revised regulation will appear at 

section 35.37(e)(3).

3. Comments of Barrick 

a. Comments

357. Barrick Goldstrike Mines (Barrick) notes that the Commission previously found 

that “mitigated sellers and their affiliates are prohibited from selling power at market 

based rates in the balancing authority area in which the seller is found, or presumed, to 

have market power.”479 Barrick also notes that, in Order No. 697, the Commission 

recognized that wholesale sales made at the metered boundary for export lend 

themselves to being monitored for compliance and concluded to allow mitigated sellers 

to make such sales.480 Barrick further notes that in Order No. 697, to ensure that the 

 

479 Barrick at 6 (citing Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 at P 42)

(emphasis added by Barrick). Barrick states that “affiliate” is broadly defined in the 

market-based rate regulation and may need to be refined to be limited to the relationship 

between a franchised public utility with captive customers and its associated marketregulated power sales company. Id.

480 Id. at 7 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 820).
Docket No. RM14-14-000 220

mitigated seller and its directly related companies did not sell the same power purchased 

by a third party at the metered boundary back into the balancing authority area where the 

seller is mitigated, the Commission imposed record keeping requirements for these 

sales.481 Barrick states that, “rather than dealing with the additional regulatory burdens 

and risk of non-compliance,” mitigated sellers may instead choose not to make any 

market-based rate sales at the metered boundary and that this is problematic.482 Barrick 

argues that permitting affiliates to choose not to sell at a metered boundary hinders the 

development of more robust competition. Barrick also represents that Berkshire

Hathaway Energy Company’s affiliates have elected not to sell in a market based on a 

rebuttable presumption that a seller has market power, but have done nothing to rebut or 

substantiate that presumption.483 Barrick suggests that the Commission reevaluate the 

mitigation rules and the definition of “affiliate” in certain cases.

484

 

481 Id.

482 Id. (emphasis by Barrick).

483 Id. at 8-9.

484 In particular, where (a) no RTO or ISO exists in the region so parties must 

depend on bilateral contracts; (b) dominant utility power suppliers with geographically 

large balancing authority areas and common ownership due to consolidation are present; 

(c) construction of electric generation facilities in these geographically large balancing 

authority areas is dominated by the utility power suppliers because they have relatively 

easy access to funding through retail ratepayer funding; and (d) dominant utility power 

suppliers are refusing to sell wholesale power into balancing authority areas, even where 

they have not been found to have market power. Id. at 7-8 (arguing that Order No. 697 

did not adequately anticipate the possibilities brought about by the repeal of PUHCA of 

1938, so now entities, are becoming too big to regulate with traditional rules).
Docket No. RM14-14-000 221

358. Barrick further asserts that Order No. 697 should be amended in such a way to 

allow full optimization of imbalance energy across the broader footprint of CAISO 

Energy Imbalance Market485 (EIM) and the sharing of other resources within the 

Northwest Power Pool.486 Barrick states that the mitigation rules adopted in Order No. 

697 cause imbalance energy across the broader CAISO EIM footprint to not be optimized 

despite the fact that transmission between the entities in the EIM is available, resulting in 

the inefficient implementation of the CAISO EIM.487 

b. Commission Determination

359. With respect to Barrick’s requests to revisit the Commission’s findings in Order 

No. 697 that “mitigated sellers and their affiliates are prohibited from selling power at 

market-based rates in the balancing authority area in which the seller is found, or 

presumed, to have market power” and the definition of “affiliate,” at least in certain 

 

485 Id. at 10, 13 (citing Cal. Indep. Sys. Operator Corp., Transmittal Letter, Docket 

No. ER14-1836-000 (filed Feb. 28, 2014) and Cal. Indep. Sys. Operator Corp., 147 

FERC ¶ 61,231 (2014)).

486 Id. at 10-13.

487 Id. at 11 (explaining that CAISO and NV Energy will be able to purchase and 

sell five-minute real-time energy under a market-driven regime for meeting energy 

imbalance needs, and CAISO and PacifiCorp will be able to purchase and sell fiveminute real-time energy under a market-driven regime for meeting energy imbalance 

needs, but PacifiCorp and NV Energy will not be able to purchase and sell five-minute 

real-time energy under a market-driven regime for meeting energy imbalance needs).
Docket No. RM14-14-000 222

cases, we find that they are beyond the scope of this rulemaking. Accordingly, we will 

not address Barrick’s comments in this Final Rule.488

V. Section-by-Section Analysis of Regulations

1. Section 35.36 Generally

360. This section defines certain terms specific to Subpart H and explains the 

applicability of Subpart H.

361. The NOPR proposed to redefine “Category 1 Seller” in paragraph (a)(2) to clarify 

the distinction in determining the seller category status of power marketers and power 

producers. Specifically, that for purposes of determining category status, a power 

marketer should include all affiliated generation capacity in that region, but that a power 

producer only needs to include affiliated generation that is located in the same region as 

the power producer’s generation assets.

362. The Final Rule adopts the regulatory text changes proposed in the NOPR 

regarding the definition of Category 1 Seller in paragraph (a)(2). 

2. Section 35.37 Market power analysis required

363. This section describes the market power analysis the Commission employs, as 

discussed in the preamble, and when sellers must file one. It is intended to identify the 

key aspects of the analysis.

364. The NOPR proposed to change the reference in paragraph (a)(1) for the location 

 

488 Additionally, reply comments were filed in response to Barrick’s comments but 

they are not permitted in this proceeding. 
Docket No. RM14-14-000 223

of the regional reporting schedule from Order No. 697 to the Commission’s website. The 

NOPR proposed to add a requirement in paragraph (a)(2) that sellers include as part of 

their updated market power analyses, an organizational chart depicting their current 

corporate structure, indicating all upstream owners, energy subsidiaries and energy 

affiliates. The NOPR proposed to revise paragraph (c)(4) to specify that sellers must file 

their indicative screens in an electronic spreadsheet format. The NOPR proposed to add 

paragraph (c)(5) to require that sellers use the format provided in Appendix A of subpart 

H of part 35 and, if applicable, file SIL Submittals 1 and 2 in the electronic spreadsheet 

format provided on the Commission’s website. The NOPR also proposed to add 

paragraph (c)(6) to provide that sellers in RTO/ISO markets with Commission-approved 

market monitoring and mitigation may, in lieu of submitting the indicative screens, 

include a statement that they are relying on such mitigation to address any potential 

horizontal market power concerns. The NOPR proposed to remove paragraph (e)(2) to 

remove the requirement that sellers address sites for generation capacity development as 

part of their market power analyses and to renumber paragraphs (e)(3) and (e)(4) as 

paragraphs (e)(2) and (e)(3) respectively and to revise new paragraph (e)(3) to clarify that 

the vertical market power affirmative statement must be made on behalf of the seller and 

its affiliates.

365. The Final Rule adopts the regulatory text changes proposed in the NOPR 

regarding the location of the schedule for updated market power filings in paragraph 

(a)(1). The Final Rule also adopts the NOPR proposal to revise the language in 

paragraph (a)(2) to require an organizational chart; however the language varies from that 
Docket No. RM14-14-000 224

proposed in the NOPR to limit the organizational chart to depicting affiliates as discussed 

in the Corporate Families discussion above. The Final Rule also adopts the NOPR 

regulatory text changes to paragraphs (c)(4) and (c)(5) regarding submission of the 

indicative screens and SIL Submittals 1 and 2 in electronic spreadsheet formats. 

Consistent with the Horizontal Market Power discussion, the Final Rule does not adopt 

the NOPR proposal to add a new paragraph allowing sellers in RTO/ISO markets to rely 

on market monitoring and mitigation in lieu of submitting indicative screens. The Final 

Rule adopts the NOPR proposal to amend the language of paragraph (e)(3) to clarify that 

the affirmative statement must be made on behalf of the seller and its affiliates.

3. Section 35.42 Change in status reporting requirement

366. The NOPR proposed several revisions to the regulation, including a change to 

paragraph (a)(1) to clarify that the 100 MW reporting threshold is not limited to market 

previously studied and includes both the relevant market and any first-tier markets. The 

NOPR proposed a change to paragraph (a)(2)(i) to apply a 100 MW threshold for 

reporting new affiliations and to include in that threshold long-term firm purchases of 

capacity and/or energy and to included cumulative increases in the first-tier markets as 

well as the relevant market. The NOPR also proposed to revise paragraph (c) to require 

sellers to submit organizational chart unless the change in status does not affect the 

seller’s structure. In addition, the NOPR proposed revisions to paragraph (b) to remove a 

reference to change in status filings to report acquisition of control of sites for new 
Docket No. RM14-14-000 225

generation capacity development and to remove paragraphs (d) and (e), which address 

site control reporting, which is being eliminated as explained in the Notices of Change in 

Status discussion.

367. The Final Rule adopts the proposed edits to paragraph (a) except as discussed 

herein. In paragraphs (a)(1) and (a)(2)(i), the language proposed in the NOPR including 

first-tier markets is not included in accordance with the Notices of Change in Status 

discussion and the requirement is limited to 100 MW or more change in any individual 

relevant geographic market. The Final Rule adopts the NOPR proposal to add a 100 MW 

threshold to the change in status reporting requirement and, consistent with the Capacity 

Ratings discussion, adds language in paragraph (a)(2)(i) to specify that energy-limited 

resources may use a five-year capacity rating for purposes of calculating the threshold.

368. Consistent with the Vertical Market Power – Land Acquisition Reporting 

discussion, the Final Rule adopts the proposals to remove references to reporting new 

sites for generation capacity development, removing paragraphs (d) and (e) in their 

entirety and deleting the reference to site reporting from paragraph (b).

369. Finally, the Final Rule adopts the proposed edits to paragraph (c) except as 

discussed herein. Consistent with the Corporate Organizational Charts discussion, the 

Final Rule does not include the reference to upstream owners and energy subsidiaries, 

and requires only that the organizational charts indicate all affiliates. 
Docket No. RM14-14-000 226

4. Miscellaneous 

VI. Information Collection Statement

370. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection and data retention requirements imposed by agency 

rules.489 Upon approval of a collection(s) of information, OMB will assign an OMB 

control number and an expiration date. Respondents subject to the filing requirements of 

a rule will not be penalized for failing to respond to these collections of information 

unless the collections of information display a valid OMB control number. 

371. The Commission is submitting the proposed modifications to its information 

collections to OMB for review and approval in accordance with section 3507(d) of the 

Paperwork Reduction Act of 1995.490 In the NOPR, the Commission solicited comments 

on the Commission’s need for this information, whether the information will have 

practical utility, the accuracy of the burden estimates, ways to enhance the quality, utility, 

and clarity of the information to be collected or retained, and any suggested methods for 

minimizing respondents’ burden, including the use of automated information techniques. 

The Commission included a table that listed the estimated public reporting burdens for 

the proposed reporting requirements, as well as a projection of the costs of compliance 

for the reporting requirements.

 

489 5 CFR 1320.11(b) (2015).

490 44 U.S.C. 3507(d) (2012).
Docket No. RM14-14-000 227

Comments

372. In response to the Commission’s proposals regarding changes to the indicative 

screen reporting requirements, EEI notes that, if the Commission wants sellers to submit 

the indicative screens in Appendix A in formats other than the standard formats, such as 

Adobe, Excel, or Word, the Commission should acknowledge that requiring the use of 

more complex formats and new details in Appendix A will entail some additional burden 

on sellers filing the information, at least during the initial round of using such formats.491

Commission Determination

373. We revise the Information Collection Statement estimates contained in the NOPR

because the Commission has made several changes to its NOPR proposal in this Final 

Rule, which are discussed below. 

374. First, we do not adopt in the Final Rule the NOPR proposal to eliminate the 

requirement in section 35.37492 to file the indicative screens as part of a horizontal market 

power analysis for any seller in an RTO if the seller is relying on Commission-approved 

monitoring and mitigation to mitigate any potential market power it may have. The 

NOPR presupposed a decrease in its burden estimate regarding this proposal, and we 

have adjusted the burden estimate in the table below to reflect that this burden will not 

change from current regulations.

 

491 EEI at 10.

492 18 CFR 35.37.
Docket No. RM14-14-000 228

375. Second, we will modify the NOPR’s proposal to require sellers to file corporate 

organizational charts including all upstream owners, energy subsidiaries, and energy 

affiliates in initial market-based rate applications and related filings. The organizational 

charts will still be required, but they will be limited to include the seller’s affiliates as 

defined in section 35.36(a)(9) of the Commission’s regulations rather than all upstream 

owners, “energy subsidiaries” and “energy affiliates.” This modification of the NOPR 

proposal constitutes a small burden decrease from the NOPR. Because the corporate 

organizational chart filing is similar to that proposed in the NOPR, we are not modifying 

the estimated public reporting burdens for this proposed reporting requirement in the 

table below. We believe that the revised burden estimates below are representative of the 

average burden on filers.

376. Third, we do not adopt the NOPR proposal to clarify that sellers must report 

behind-the-meter generation in the indicative screens and asset appendices, and have such 

generation count toward change in status and category status thresholds. These changes 

represent a small decrease in burden due to the reduction in filings from not including 

behind-the-meter generation as part of the 100 MW generation threshold to trigger filing 

a notice of change in status for new affiliations.

377. Fourth, we modify the NOPR’s proposed changes to the asset appendix by (1) 

requiring separate worksheets in the Asset Appendix for long-term PPAs and end notes, 

(2) adding new columns to the generation asset list for explanatory end note numbers 

and information regarding capacity ratings, and (3) adding new columns to the 

transmission list for citation to the order accepting the OATT or approving transfer of 
Docket No. RM14-14-000 229

transmission facility to an RTO/ISO and explanatory end note numbers. The NOPR 

presupposed a burden decrease in its burden estimate regarding this proposal, and we 

have adjusted the burden estimate in the table below to reflect that, as amended, the 

burden will not change from current regulations. While these changes represent a small 

increase in burden, this burden is counterbalanced by the decrease in burden from 

eliminating the proposed requirements to report behind-the-meter generation in 

indicative screens and for change in status and seller category thresholds. Thus, we 

believe that the overall burden will not change when these two changes are averaged 

together. 

378. In response to EEI’s comment that the use of more complex formats for 

indicative screens will entail additional burden, Commission regulations already require 

the submission of indicative screens, and the Final Rule adopts the NOPR proposal to 

require these screens in electronic format. We view this as a de minimis decrease in 

burden for several reasons. While the new rows in the indicative screens may appear to 

require additional information to complete the screens (e.g., rows A1, B1, L1, M, U, and 

V in the market share screen), the information entered in these new rows is simply 

disaggregated information that was previously required, but often erroneously 

aggregated into values in other rows. Requiring sellers to explicitly enter this 

information will reduce computation errors and subsequent phone calls from staff to 

correct problems in the screens. Also, these new screens are workable electronic 

spreadsheets with pre-programmed formulas in certain cells that compute intermediate 

and final cell values. Embedding these pre-programmed formulas into the worksheet 
Docket No. RM14-14-000 230

will reduce the amount of time that sellers will spend creating and calculating the 

indicative screens, increase the accuracy of the values entered (e.g., sellers will now 

enter only positive values and no longer have to enter values surrounded by parentheses 

to indicate a negative value), and eliminate computation errors that sellers have 

frequently made in the past. Thus, we consider the electronic format and the additional 

columns of information in the indicative screens to average out to be a de minimis

decrease in burden for filers and project that the average burden on filers will not change 

from current regulations.

FERC-919 (Final Rule in RM14-14-000)

Number of 

Respondents

(1)

Annual Number 

of Responses 

per Respondent

(2)

Total 

Number of 

Responses 

(1)*(2)=(3)

Average 

Burden & 

Cost Per 

Response493

(4)

Total Annual 

Burden 

Hours & 

Total Annual 

Cost

(3)*(4)=(5)

Cost per 

Respondent

($)

(5)÷(1)

New 

Applications for 

Market-Based 

Rates (18 CFR 

35.37

213 1 213 250494

$21,268

53,250

$4,529,998

$21,268

 

493 The Commission estimates this figure based on the Bureau of Labor Statistics 

data (for the Utilities sector, at http://www.bls.gov/oes/current/naics2_22.htm, plus 

benefits information at http://www.bls.gov/news.release/ecec.nr0.htm). The salaries 

(plus benefits) for the three occupational categories are:

 Economist: $67.75/hour

 Electric Engineer: $59.62/hour

 Lawyer: $128.02/hour

($67.57 + $59.62 + $128.02) ÷ 3 = $85.07

494 The Commission notes that the estimate of 250 hours per new application is a 

conservative estimate and most likely overstates burden because some sellers (i.e., power 

marketers with no generation to study and sellers that only have fully committed

generation) will not have to file indicative screens with their initial applications.
Docket No. RM14-14-000 231

Triennial 

Market Power 

Analysis in 

Category 2 

Seller Updates 

(18 CFR 35.37)

83 1 83 250

$21,268

20,750

$1,765,203

$21,268

Quarterly Land 

Acquisition 

Reports 

[18 CFR 

35.42(d)]

0 0 0 0

$0

0

$0

$0

Change in 

Status Reports 

[18 CFR 

35.42(a)], With 

Screens

27 1 27 250

$21,268

6,750

$574,222

$21,268

Change in 

Status reports 

[18 CFR 

35.42(a)], No 

Screens

186 1 186 20

$1,701

3,720

$316,460

$1,701

TOTAL 509 84,470

$7,185,883

$14,118

After implementation of the proposed changes, the total estimated annual cost of burden 

to respondents is $7,185,882.90 [84,470 hours × $85.07495) = $7,185,882.90]. 

Title: Proposed Revisions to Market Based Rates for Wholesale Sales of Electric Energy, 

Capacity and Ancillary Services by Public Utilities (FERC-919).

 

495 The Commission estimates this figure based on the Bureau of Labor Statistics 

data (for the Utilities sector, at http://www.bls.gov/oes/current/naics2_22.htm, plus 

benefits information at http://www.bls.gov/news.release/ecec.nr0.htm). The salaries 

(plus benefits) for the three occupational categories are:

 Economist: $67.75/hour

 Electric Engineer: $59.62/hour

 Lawyer: $128.02/hour

($67.57+$59.62+$128.02) /3 = $85.07
Docket No. RM14-14-000 232

Action: Revision of Currently Approved Collection of Information. 

OMB Control No.: 1902-0234

Respondents for this Rulemaking: Public utilities, wholesale electricity sellers, 

businesses, or other for profit and/or not for profit institutions.

Frequency of Responses: 

Initial Applications: On occasion.

Updated Market Power Analyses: Updated market power analyses are filed every three 

years by Category 2 sellers seeking to retain market-based rate authority. 

Land Acquisitions: We will eliminate this requirement under the Final Rule.

Change in Status Reports: On occasion. 

Necessity of the Information: 

Initial Applications: In order to receive market-based rate authority, the Commission 

must first evaluate whether a seller has the ability to exercise market power. Initial 

applications help inform the Commission as to whether an entity seeking market-based 

rate authority lacks market power, and whether sales by that entity will be just and 

reasonable.

Updated Market Power Analyses: Triennial updated market power analyses allow the 

Commission to monitor market-based rate sellers to detect changes in market power or 

potential abuses of market power. The updated market power analysis permits the 

Commission to determine that continued market-based rate authority will still yield rates 

that are just and reasonable.
Docket No. RM14-14-000 233

Change in Status Reports: The change in status requirement provides the Commission 

with information regarding changes that could affect facts the Commission relied upon in 

granting market-based rate authority and thus permits the Commission to ensure that rates 

and terms of service offered by market-based rate sellers remain just and reasonable.

Internal Review: The Commission has reviewed the reporting requirements and made a 

determination that revising the reporting requirements will ensure the Commission has 

the necessary data to carry out its statutory mandates, while eliminating unnecessary 

burden on industry. The Commission has assured itself, by means of its internal review, 

that there is specific, objective support for the burden estimate associated with the 

information requirements. 

379. Interested persons may obtain information on the reporting requirements by 

contacting: Federal Energy Regulatory Commission, 888 First Street, NE, Washington, 

DC 20426 [Attention: Ellen Brown, Office of the Executive Director, e-mail: 

DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873]. Comments 

concerning the requirements of this rule may also be sent to the Office of Information and 

Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 

[Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security 

reasons, comments should be sent by e-mail to OMB at oira_submission@omb.eop.gov. 

Comments submitted to OMB should refer to FERC-919 and OMB Control Number 

1902-0234.
Docket No. RM14-14-000 234

VII. Environmental Analysis

380. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse 

effect on the human environment.496 The Commission has categorically excluded 

certain actions from this requirement as not having a significant effect on the human 

environment. Included in the exclusion are rules that are clarifying, corrective, or 

procedural, or that do not substantially change the effect of the regulations being 

amended.497 The actions here fall within this categorical exclusion in the Commission’s 

regulations.

VIII. Regulatory Flexibility Act

381. The Regulatory Flexibility Act of 1980 (RFA)

498 generally requires a description 

and analysis of proposed rules that will have significant economic impact on a substantial 

number of small entities. Thus, the Commission estimates that the rulemaking will 

impose only a minimal additional burden on responsible entities, as described below. 

382. The final rule in RM14-14-000 is expected to impose an additional burden on 

2,002 entities. Comparison of the applicable entities with FERC’s small business data 

 

496 Regulations Implementing the National Environmental Policy Act of 1969, 

Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations 

Preambles 1986-1990 ¶ 30,783 (1987).

497 18 CFR 380.4(a)(2)(ii).

498 5 U.S.C. 601-612 (2012).
Docket No. RM14-14-000 235

indicates that approximately 1,634, or 82 percent499of the 2,002 entities are small entities

affected by this Final Rule.

500

383. On average, each small entity affected may have a one-time cost of $4,207.19, 

representing 84,470 hours at $67.57/hour (for economists), $59.62/hour (for electrical 

engineers), and $128.02/hour (for lawyers). These figures represent the implementation 

burden of the changes to FERC-919 per the RM14-14-000 Final Rule, as explained above 

in the information collection statement. Accordingly, the Commission certifies that this 

rulemaking will not have a significant economic impact on a substantial number of small 

entities. The Commission seeks comment on this certification.

IX. Document Availability

384. 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.

 

499 81.6 percent.

500 The Small Business Administration sets the threshold for what constitutes a 

small business. Public utilities may fall under one of several different categories, 

each with a size threshold based on the company’s number of employees, including 

affiliates, the parent company, and subsidiaries. For the analysis in this Final Rule, we 

use a 750 employee threshold for each affected entity. Each entity is classified as 

Electric Bulk Power Transmission and Control (NAICS code 221121), Fossil Fuel 

Generation (NAICS code 221112), or Nuclear Power Generation (NAICS code 221113). 
Docket No. RM14-14-000 236

385. 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.

386. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from the Commission’s Online Support at (202) 502-6652 (toll 

free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 

Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.

X. Effective Date and Congressional Notification

387. This Final Rule is effective [insert date 90 days after publication in the 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. This Final Rule is being submitted to the Senate, House, and Government 

Accountability Office.
Docket No. RM14-14-000 237

List of subjects in 18 CFR Part 35 

Electric power rates, Electric utilities, Reporting and recordkeeping requirements.

By the Commission. 

( S E A L )

Kimberly D. Bose,

Secretary.
Docket No. RM14-14-000 238

In consideration of the foregoing, the Commission amends part 35, 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 § 35.36 by revising paragraph (a)(2) to read as follows:

§ 35.36 Generally.

(a) * * *

(2) A Category 1 Seller means a Seller that:

(i) Is either a wholesale power marketer that controls or is affiliated with 500 MW 

or less of generation in aggregate per region or a wholesale power producer that owns, 

controls or is affiliated with 500 MW or less of generation in aggregate in the same 

region as its generation assets; 

(ii) Does not own, operate or control transmission facilities other than limited 

equipment necessary to connect individual generating facilities to the transmission grid 

(or has been granted waiver of the requirements of Order No. 888, FERC Stats. & Regs. 

¶ 31,036); 

(iii) Is not affiliated with anyone that owns, operates or controls transmission 

facilities in the same region as the Seller's generation assets; 

(iv) Is not affiliated with a franchised public utility in the same region as the 

Seller's generation assets; and 
Docket No. RM14-14-000 239

(v) Does not raise other vertical market power issues.

* * * * *

3. Amend § 35.37 as follows:

a. In paragraph (a)(1), remove the phrase “contained in Order No. 697, FERC 

Stats. & Regs. ¶ 31,252” and add in its place “posted on the Commission’s website.”

b. Revise paragraphs (a)(2) and (c)(4).

c. Add paragraph (c)(5).

d. Remove paragraph (e)(2) and redesignate paragraphs (e)(3) through (4) as 

paragraphs (e)(2) through (3), respectively.

e. Revise newly redesignated paragraph (e)(3).

The revisions and additions read as follows:

§ 35.37 Market Power analysis required.

(a) * * *

(2) When submitting a market power analysis, whether as part of an initial 

application or an update, a Seller must include an appendix of assets, in the form 

provided in Appendix B of this subpart, and an organizational chart. The organizational 

chart must depict the Seller’s current corporate structure indicating all affiliates. 

* * * * *

(c) * * *

(4) When submitting the indicative screens, a Seller must use the format 

provided in Appendix A of this subpart and file the indicative screens in an electronic 

spreadsheet format. A Seller must include all supporting materials referenced in the 
Docket No. RM14-14-000 240

indicative screens. 

(5) Sellers submitting simultaneous transmission import limit studies must 

file Submittal 1, and, if applicable, Submittal 2, in the electronic spreadsheet format 

provided on the Commission’s website. 

* * * * *

(e) * * *

(3) A Seller must ensure that this information is included in the record of each 

new application for market-based rates and each updated market power analysis. In 

addition, a Seller is required to make an affirmative statement that it and its affiliates 

have not erected barriers to entry into the relevant market and will not erect barriers to 

entry into the relevant market.

* * * * *

4. Amend § 35.42 as follows:

a. Revise paragraphs (a)(1), (a)(2), and (c).

b. In paragraph (b), remove the phrase “, other than a change in status submitted 

to report the acquisition of control of a site or sites for new generation capacity 

development,”.

c. Remove paragraphs (d) and (e).

The revisions read as follows:

§ 35.42 Change in status reporting requirement.

(a) * * *
Docket No. RM14-14-000 241

(1) Ownership or control of generation capacity or long-term firm purchases of 

capacity and/or energy that results in cumulative net increases (i.e., the difference 

between increases and decreases in affiliated generation capacity) of 100 MW or more of 

nameplate capacity in any individual relevant geographic market, or of inputs to electric 

power production, or ownership, operation or control of transmission facilities, or

(2) Affiliation with any entity not disclosed in the application for market-based 

rate authority that:

(i) Owns or controls generation facilities or has long-term firm purchases of 

capacity and/or energy that results in cumulative net increases (i.e., the difference 

between increases and decreases in affiliated generation capacity) of 100 MW or more of 

capacity based on nameplate or seasonal capacity ratings, or, for energy-limited 

resources, five-year average capacity factors, in any individual relevant geographic 

market; 

(ii) Owns or controls inputs to electric power production;

(iii) Owns, operates or controls transmission facilities; or 

(iv) Has a franchised service area.

* * * * *

(c) When submitting a change in status notification regarding a change that 

impacts the pertinent assets held by a Seller or its affiliates with market-based rate 

authorization, a Seller must include an appendix of all assets, including the new assets 

and/or affiliates reported in the change in status, in the form provided in Appendix B of 

this subpart, and an organizational chart. The organizational chart must depict the 
Docket No. RM14-14-000 242

Seller’s prior and new corporate structures indicating all affiliates unless the Seller 

demonstrates that the change in status does not affect the corporate structure of the 

Seller’s affiliations. 
Docket No. RM14-14-000 243

5. Revise Appendix A to Subpart H to read as follows:

Appendix A to Subpart H of Part 35
Docket No. RM14-14-000 244

Appendix A: Standard Screen Format (Data provided for illustrative purposes only)

Part I – Pivotal Supplier Analysis 

Staff Notes:

The file differs from the file published in the NOPR:

1. All entered values must be positive (no parenthesis/negative numbers)

2. The formulas (and the text in the row description) have been changed to reflect number 1.

3. The text in row 13 "Date of Filing" has been replaced with "Data Year"

4. Instruction: Enter all numeric values as positive numbers (blue values)

 Don't enter values into an outlined cell (black values)

Applicant-> Company X, LLC (TO)

Market -> Company X BAA

 Data Year -> Dec 2011-Nov 2012

Row

Generation Reference

Seller and Affiliate Capacity (owned or controlled)

A Installed Capacity (from inside the study area) 1,500 worksheet X

A1 Remote Capacity (from outside the study area) 200 worksheet X

B Long-Term Firm Purchases (from inside the study area) 70 worksheet X

B1 Long-Term Firm Purchases (from outside the study area) 200 worksheet X

C Long-Term Firm Sales (in and outside the study area) 500 worksheet X

D Uncommitted Capacity Imports 0 worksheet X

Non-Affiliate Capacity (owned or controlled)

E Installed Capacity (from inside the study area) 300 worksheet X

E1 Remote Capacity (from outside the study area) 50 worksheet X

F Long-Term Firm Purchases (from inside the study area) 40 worksheet X

F1 Long-Term Firm Purchases (from outside the study area) 40 worksheet X

G Long-Term Firm Sales (in and outside the study area) 60 worksheet X

H Uncommitted Capacity Imports 2,500 worksheet X

I Study Area Reserve Requirement 300 worksheet X

J Amount of Line I Attributable to Seller, if any 200

K Total Uncommitted Supply (A+A1+B+B1+D+E+E1+F+F1+H-C-G-I-M) 2,840

Load

L Balancing Authority Area Annual Peak Load 1,500 worksheet X

M Average Daily Peak Native Load in Peak Month 1,200 worksheet X

N Amount of Line M Attributable to Seller, if any 900 worksheet X

O Wholesale Load (L-M) 300

P Net Uncommitted Supply (K-O) 2,540

Q Seller's Uncommitted Capacity (A+A1+B+B1+D-C-J-N) 370

Result of Pivotal Supplier Screen (Pass if Line Q < Line P) Pass

 (Fail if Line Q > Line P)

Total Imports (Sum D,H), as filed by Seller -> 2,500

% of SIL for Seller's imported capacity -> 0.00

% of SIL for Other's imported capacity -> 1.00

SIL value* -> 2,500

Do Total Imports exceed the SIL value? -> No

* Transmission owners filing triennials should use the SIL values from their Submittal 1, Row 10 (see Puget Sound Energy, Inc., 135 FERC ¶ 61,254 (2011)).

Other sellers should use Commission-accepted SIL values, if they exist for the study area and study period. If these values do not exist, sellers should

use SIL values that have been filed but not accepted.
Docket No. RM14-14-000 245

Appendix A: Standard Screen Format (Data provided for illustrative purposes only)

Part II – Market Share Analysis 

Staff Notes:

The file differs from the file published in the NOPR:

1. All entered values must be positive (no parenthesis/negative numbers)

2. The formulas (and the text in the row description) have been changed to reflect number 1.

3. Instruction: Enter all numeric values as positive numbers (blue values)

 Don't enter values into an outlined cell (black values)

Applicant-> Company X, LLC (TO)

Study Area -> Company X BAA

Data Year -> Dec 2011-Nov 2012

As filed by the Applicant/Seller

Row Winter Spring Summer Fall Reference

(MW) (MW) (MW) (MW)

Seller and Affiliate Capacity (owned, controlled or under LT contract)

A Installed Capacity (inside the study area) 1,000 900 1,500 1,000 worksheet X

A1 Remote Capacity (from outside the study area) 400 300 200 200 worksheet X

B Long-Term Firm Purchases (inside the study area) 60 40 70 30 worksheet X

B1 Long-Term Firm Purchases (from outside the study area) 200 200 200 200 worksheet X

C Long-Term Firm Sales (in and outside the study area) 500 500 500 500 worksheet X

D Seasonal Average Planned Outages 150 50 80 100 worksheet X

E Uncommitted Capacity Imports 0 0 0 0 worksheet X

Capacity Deductions

F Average Peak Native Load in the Season 1,000 900 1,200 800 worksheet X

G Amount of Line F Attributable to Seller, if any 700 700 900 600 worksheet X

H Amount of Line F Attributable to Non-Affiliates, if any 300 200 300 200

I Study Area Reserve Requirement 200 200 300 100 worksheet X

J Amount of Line I Attributable to Seller, if any 100 100 200 80 worksheet X

K Amount of Line I Attributable to Non-Affiliates, if any 100 100 100 20

Non-Affiliate Capacity (owned, controlled or under LT contract)

L Installed Capacity (inside the study area) 250 200 300 150 worksheet X

L1 Remote Capacity (from outside the study area) 50 50 50 50 worksheet X

M Long-Term Firm Purchases (inside the study area) 30 30 30 30 worksheet X

M1 Long-Term Firm Purchases (from outside the study area) 40 30 40 20 worksheet X

N Long-Term Firm Sales (in and outside the study area) 50 30 60 50 worksheet X

O Seasonal Average Planned Outages 10 20 10 20 worksheet X

P Uncommitted Capacity Imports 2,000 1,500 2,500 1,300 worksheet X

Supply Calculation

Q Total Competing Supply (L+L1+M+M1+P-H-K-N-O) 1,910 1,460 2,450 1,260

R Seller's Uncommitted Capacity (A+A1+B+B1+E-C-D-G-J) 210 90 290 150

S Total Seasonal Uncommitted Capacity (Q+R) 2,120 1,550 2,740 1,410

T Seller's Market Share (R÷S) 9.9% 5.8% 10.6% 10.6%

Results (Pass if < 20% and Fail if ≥ 20%) Pass Pass Pass Pass

U Total Imports, as filed by Seller (E+P) 2,000 1,500 2,500 1,300

V SIL value* 2,000 1,500 2,500 1,300

Do Total Imports exceed SIL value? (is U<=V) No No No No

* Transmission owners filing triennials should use the SIL values from their Submittal 1, Row 10 (see Puget Sound Energy, Inc., 135 FERC ¶ 61,254 (2011)).

Other sellers should use Commission-accepted SIL values, if they exist for the study area and study period. If these values do not exist, sellers should

use SIL values that have been filed but not accepted.
Docket No. RM14-14-000 246

6. Revise Appendix B to Subpart H to read as follows:

Appendix B to Subpart H of Part 35
Docket No. RM14-14-000 247

Instructions for completing the Asset Appendix list: Long-term Purchased Power Agreements (PPA)

Column Title Format Description

[A] Filing Entity and its Energy Affiliates Free Form Text

Name of the Filing Entity or affiliate of the Filing Entity that is 

purchasing the energy or capacity.

[B] Docket # where MBR authority was 

granted 

Text in the form: ##XX-XXX-XXX where 

"##" is either "ER" or "QF" and "X" is a digit Same instruction as the Generation Assets Tab.

[C] Seller Name Free Form Text Name of the Entity that is selling the energy or capacity.

[D] Amount of PPA (MW) Numeric. Either an integer or fixed width 

numeric with one decimal

Contracted amount of MW of the PPA. If the contract is for the entire 

output of a specific generation facility, you may de-rate the facility 

using the same de-rating methodology that is used for generators of 

the same technology elsewhere in the appendix. If this amount is derated please explain in the end notes section. Energy only contracts 

must be converted from MwH to MW and only report contracts one 

year or longer 

[E] Market / Balancing Authority Area

Free Form Text. For Markets or 

submarkets please use one of the 

abbreviations or names in the next 

column. For BAAs please use the NERC 

defined name

The RTO/ISO, RTO/ISO submarket, or NERC defined balancing 

authority area where the generation or capacity is physically located.

[F] Geographic Region Specific Text Same instruction as the Generation Assets Tab

[G] Start Date (mo/da/yr) MM/DD/YY The Start Date of the PPA

[H] End Date (mo/da/yr) MM/DD/YY The End Date of the PPA

[I] End Note Number (Enter text in End 

Note Tab) Integer Same instruction as the Generation Assets Tab
Docket No. RM14-14-000 248
Docket No. RM14-14-000 249
Docket No. RM14-14-000 250

Note: The following appendices will not be published in the Code of Federal

Regulations.

Appendix C 

Filing Period 

(anytime during 

this month)

Northeast Transmission Owning Utilities December 2011 to November 2012 December: 2013

Southeast Transmission Owning Utilities December 2011 to November 2012 June: 2014

Central Transmission Owning Utilities December 2012 to November 2013 December: 2014

SPP Transmission Owning Utilities December 2012 to November 2013 June: 2015

Southwest Transmission Owning Utilities December 2013 to November 2014 December: 2015

Northwest Transmission Owning Utilities December 2013 to November 2014 June: 2016

Northeast Transmission Owning Utilities December 2014 to November 2015 December: 2016

Southeast Transmission Owning Utilities December 2014 to November 2015 June: 2017

Central Transmission Owning Utilities December 2015 to November 2016 December: 2017

SPP Transmission Owning Utilities December 2015 to November 2016 June: 2018

Southwest Transmission Owning Utilities December 2016 to November 2017 December: 2018

Northwest Transmission Owning Utilities December 2016 to November 2017 June: 2019

Northeast Transmission Owning Utilities December 2017 to November 2018 December: 2019

Southeast Transmission Owning Utilities December 2017 to November 2018 June: 2020

Central Transmission Owning Utilities December 2018 to November 2019 December: 2020

SPP Transmission Owning Utilities December 2018 to November 2019 June: 2021

Southwest Transmission Owning Utilities December 2019 to November 2020 December: 2021

Northwest Transmission Owning Utilities December 2019 to November 2020 June: 2022

Northeast Transmission Owning Utilities December 2020 to November 2021 December: 2022

Southeast Transmission Owning Utilities December 2020 to November 2021 June: 2023

Central Transmission Owning Utilities December 2021 to November 2022 December: 2023

SPP Transmission Owning Utilities December 2021 to November 2022 June: 2024

Southwest Transmission Owning Utilities December 2022 to November 2023 December: 2024

Northwest Transmission Owning Utilities December 2022 to November 2023 June: 2025

Schedule for Transmission Owning Utilities with Market-based Rate Authority that are 

Designated as Category 2 Sellers in the Region

Entities Required to File Study Period
Docket No. RM14-14-000 251

Appendix C1

Filing Period 

(anytime during 

this month)

Northwest Non-Transmission Owning Utilities December 2010 to November 2011 December: 2013

Northeast Non-Transmission Owning Utilities December 2011 to November 2012 June: 2014

Southeast Non-Transmission Owning Utilities December 2011 to November 2012 December: 2014

Central Non-Transmission Owning Utilities December 2012 to November 2013 June: 2015

SPP Non-Transmission Owning Utilities December 2012 to November 2013 December: 2015

Southwest Non-Transmission Owning Utilities December 2013 to November 2014 June: 2016

Northwest Non-Transmission Owning Utilities December 2013 to November 2014 December: 2016

Northeast Non-Transmission Owning Utilities December 2014 to November 2015 June: 2017

Southeast Non-Transmission Owning Utilities December 2014 to November 2015 December: 2017

Central Non-Transmission Owning Utilities December 2015 to November 2016 June: 2018

SPP Non-Transmission Owning Utilities December 2015 to November 2016 December: 2018

Southwest Non-Transmission Owning Utilities December 2016 to November 2017 June: 2019

Northwest Non-Transmission Owning Utilities December 2016 to November 2017 December: 2019

Northeast Non-Transmission Owning Utilities December 2017 to November 2018 June: 2020

Southeast Non-Transmission Owning Utilities December 2017 to November 2018 December: 2020

Central Non-Transmission Owning Utilities December 2018 to November 2019 June: 2021

SPP Non-Transmission Owning Utilities December 2018 to November 2019 December: 2021

Southwest Non-Transmission Owning Utilities December 2019 to November 2020 June: 2022

Northwest Non-Transmission Owning Utilities December 2019 to November 2020 December: 2022

Northeast Non-Transmission Owning Utilities December 2020 to November 2021 June: 2023

Southeast Non-Transmission Owning Utilities December 2020 to November 2021 December: 2023

Central Non-Transmission Owning Utilities December 2021 to November 2022 June: 2024

SPP Non-Transmission Owning Utilities December 2021 to November 2022 December: 2024

Southwest Non-Transmission Owning Utilities December 2022 to November 2023 June: 2025

Schedule for Non-Transmission Owning Utilities with Market-based Rate Authority that are 

Designated as Category 2 Sellers in the Region

Entities Required to File Study Period
Docket No. RM04-7-000 252

Appendix D

Generalized Map of Geographic Regions

Northeast (ISO-NE, NYISO, PJM)

Southeast (SERC and FRCC NERC Regions, excluding for PJM and MISO members)

Central (Midcontinent Independent System Operator (MISO) and members of the 

Midwest Reliability Organization (MRO) that are not part of another RTO)

Southwest Power Pool (SPP NERC Region, excluding MISO members)

Southwest (Arizona, most of California, part of Nevada and the portions of New 

Mexico and Texas within the Western Interconnection)

Northwest (The remainder of the Western Interconnection)
Docket No. RM14

-14-000 253

Appendix E

Required Reporting for Simultaneous Import Limit (SIL) Studies, with Numerical Examples

Submittal 1: Summary Table of the Components Used to Calculate SIL Values 

Table 1: SIL Computation 

Instructions: 1 Delete the text 'XX' in the heading 'Study Period' and enter the last two digits of the years in the study period. 2 Delete the text 'Name of Home BAA/Market' and enter the name of the study area. 3 If you are studying more than one first-tier area, copy the relevant columns of Table 1 to empty columns

 on the right of this spreadsheet for each of the first-tier areas studied. 4 If you are studying first-tier areas, replace the text 'Name of First-Tier BAA/Market' with the name of the first-tier area(s). 5 Do not enter data in the white-background cells as these contain formulas which compute the cell values, 

 enter all megawatt values as non-negative integers in rows 1 through 3, 7 and 9 (the blue-shaded cells). 6 Note that row 5 in Table 1 is the sum of the seasonal columns from row 9 of Table 2. 7 Include an electronic copy of this spreadsheet, or a workable electronic spreadsheet with the same format and formulas

as the sample spreadsheet on the Commission Web site, with your filing. 8 The SIL Study Values (i.e., row 10 of Table 1) must be filed as part of a public document. (see note below)*

NOTE: See the footnotes below for further instruction and references to prior Commission 

direction on the component or calculation in that row.

Study Period: December 1, 20XX to November 30, 20XX

Name of First-Tier BAA/Market

Winter Spring Summer Fall Winter Spring Summer Fall

Description of Component (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) 1

Simultaneous Incremental Transfer 

Capability 

The most limiting First Contingency Incremental 

Transfer Capability (FCITC), Normal Incremental 

Transfer Capability (NITC) or equivalent values. 

Note i

1,700 1,800 1,900 2,000 3,000 3,200 3,400 3,600 2

Modeled Net Area Interchange (NAI) 

Enter a positive value and indicate the direction 

of flow in row 3 below. Note ii

500 600 700 800 200 300 400 500 3

Interchange Direction 

Indicate whether the Study Area NAI is export or 

import. 

 Import Import Import Import Export Export Export Export 4

Total Simultaneous Transfer Capability 

(row 4 = row 1 +/- row 2). Note iii 2,200 2,400 2,600 2,800 2,800 2,900 3,000 3,100 5

Long-Term Firm Transmission Reservations 

Sum of the long-term firm transmission 

reservations from Table 2. Note iv

620 300 620 300 460 360 460 360 6

Calculated SIL Value 

(row 6 = row 4 - row 5). Note v 1,580 2,100 1,980 2,500 2,340 2,540 2,540 2,740 7

Historical Peak Load 

(Identify source if not from FERC Form No. 714). 

Note vi

1,400 1,900 2,500 2,000 1,400 1,900 2,500 2,000 8

Adjusted Historical Peak Load 

(row 8 = row 7 - row 5). Note vii

 780 1,600 1,880 1,700 940 1,540 2,040 1,640 9

Uncommitted First-Tier Generation 

Amount of uncommitted generation modeled in 

the first-tier area. Note viii

13,580 12,800 14,500 12,800 13,580 12,800 14,500 12,800

10

SIL Study Value 

(row 10 = the minimum of the values entered in 

rows 6, 8 and 9 for each season). Use these SIL 

Study Values in the Market Share Screens. 

Note ix 780 1,600 1,880 1,700 940 1,540 2,040 1,640

Name of Home BAA/Market

* To the extent a filer intends to request privileged treatment for any portion of Submittals 1 or 2, such filing must 

comply with 18 CFR 388.112, including the justification for privileged treatment, i.e., why the information is exempt from 

disclosure under the mandatory public disclosure requirements of the Freedom of Information Act, 5 U.S.C. 552 (2012)
Docket No. RM14-14-000 254

Submittal 2: Identify Long-Term Firm Transmission Reservations Used to Import Power from

 Generating Resources in the First-Tier Area to Serve Historical Peak Load in the Study Area

Table 2: Long-Term Firm Transmission Reservations

Instructions: 

1 Delete the text 'Name of Home BAA/Market' and enter the name of the study area.

2 If you are studying more than one first-tier area, copy the relevant columns of Tables 1 and 2 to empty columns

 on the right of this spreadsheet for each of the first-tier areas studied.

3 If you are studying first-tier areas, replace the text 'Name of First-Tier BAA/Market' with the name of the first-tier area(s).

4 Enter all megawatt values as non-negative integers in rows 1 through 3 and 5 through 7 (the blue-shaded cells).

5 Do not enter data in the white-background cells as these cells contain formulas to compute the value in that cell.

6 Enter text to complete the “Description of Component” column as necessary in each row (e.g., enter the name of plant, describe 

 the Power Purchase Agreement or Transaction to serve non-affiliate embedded load.)

7 Use a separate line to report each Remote Plant/ Power Purchase Agreement/ Transaction to serve non-affiliate embedded load

 by inserting a new rows into the table under the existing rows for that component. For instance, to report a third Power

 Purchase Agreement for an affiliate, insert a new row between the existing row "2a" and row "3" and label that row "2b" 

8 Row 9, Sum of affiliate and non-affiliated reservations, will automatically sum the long-term reservations in that column and 

 place the total into the same seasonal column in Submittal 1, row 5, Long-Term Firm Transmission Reservations.

9 Include an electronic copy of this spreadsheet, or a workable electronic spreadsheet with the same format and formulas as the

sample spreadsheet on the Commission Web site, with your filing. (see note below)*

Name of First-Tier BAA/Market

Winter Spring Summer Fall Winter Spring Summer Fall

Description of Component (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)

Affiliates

1 MW Share of Remote Plant #1 100 - 100 - 50 50 50 50

1a MW Share of Remote Plant #2 50 50 50 50 100 - 100 - 

1b MW Share of Remote Plant #3 45 - 45 - - 50 - 50

2

Power Purchase Agreement where the energy is 

imported into the study area with long-term firm 

reservations

75 75 75 75 80 80 80 80

2a

Power Purchase Agreement where the energy is 

imported into the study area with long-term firm 

reservations

25 25 25 25

3

Transaction to serve non-affiliated load embedded 

in the study area using external generation 10 0 10 0

3a Transaction to serve non-affiliated load embedded 

in the study area using external generation 5 0 5 0

4 Sum of affiliated long-term firm reservations 310 150 310 150 230 180 230 180

Non-Affiliates

5 MW Share of Remote Plant #1 100 - 100 - 50 50 50 50

5a MW Share of Remote Plant #2 50 50 50 50 100 - 100 - 

5b MW Share of Remote Plant #3 60 - 60 - - 50 - 50

6

Power Purchase Agreement where the energy is 

imported into the study area with long-term firm 

reservations

50 50 50 50 80 80 80 80

6a

Power Purchase Agreement where the energy is 

imported into the study area with long-term firm 

reservations

25 25 25 25

7

Transaction to serve non-affiliated load embedded 

in the study area using external generation 15 15 15 15

7a

Transaction to serve non-affiliated load embedded 

in the study area using external generation 10 10 10 10

8 Sum of non-affiliated long-term firm reservations 310 150 310 150 230 180 230 180

9

Sum of affiliated and non-affiliated long-term firm 

reservations (enter value in row 5 of Table 1 

above)

620 300 620 300 460 360 460 360

Name of Home BAA/Market

* To the extent a filer intends to request privileged treatment for any portion of Submittals 1 or 2, such filing must 

comply with 18 CFR 388.112, including the justification for privileged treatment, i.e., why the information is exempt from 

disclosure under the mandatory public disclosure requirements of the Freedom of Information Act, 5 U.S.C. 552 (2012)
Docket No. RM14-14-000 255

Endnotes for Table 1:

i

See generally AEP Service Corp., 131 FERC ¶ 61,146, at P 5 (2010) (AEP) 

(“FCITC is calculated in the power flow model and represents the additional power that 

can flow into a study area by increasing available uncommitted generation in the first-tier 

area while simultaneously decreasing generation in the study area.”).

Enter an integer value for the FCITC or incremental SIL value. A negative FCITC or 

incremental SIL value may indicate a serious modeling error such as an N-0 or N-1 base 

case overload and must be addressed or explained. 

ii

See generally AEP, 131 FERC ¶ 61,146 at P 5 (“The net area interchange is also 

determined in the seasonal power flow model and represents ‘the sum of a study area’s 

scheduled energy transactions’ already flowing into and out of the study area at the 

seasonal peak that is modeled.” (citing CP&L, 128 FERC ¶ 61,039 at P 9)). 

Enter a non-negative integer value for Net Area Interchange. Different sellers apparently 

use different nomenclature to represent net imports into a study area. Here, the direction 

of the interchange, either export from or import into the study area, is explicitly declared 

in the text in row 3 and the direction is not indicated by the sign of the interchange value. 

See generally AEP, 131 FERC ¶ 61,146 at P 14 (“The Commission previously has given 

guidance on how to combine the FCITC and net area interchange values in calculating 

the SIL. However, this guidance was based on the assumption that the industry standard 

was to report a study area exporting power as a positive value (a positive net area 

interchange). SPP, however, used the reverse notation, causing some SPP Transmission 

Owners to subtract net area interchange from the FCITC value when they should have 

added.” (footnote omitted)).

iii See generally AEP, 131 FERC ¶ 61,146 at P 14 (“For a study area whose net area 

interchange represents net exports from the study area, the SIL value is equal to FCITC 

minus net exports. Therefore, net exports from a study area reduce the SIL value. 

Conversely, for a study area whose net area interchange represents net imports into the 

study area, the SIL value is equal to FCITC plus net imports. Therefore, net imports into 

a study area increase the SIL value.”); CP&L Clarification Order, 129 FERC ¶ 61,152 at 

P 23 n.15.
Docket No. RM14-14-000 256

iv See generally Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 368 (“[T]he 

Commission will require sellers to account for firm and network transmission 

reservations having a duration of longer than 28 days.”); id. P 368 n.375 (“The 

simultaneous import limit study must account for short-term firm transmission rights 

including point-to-point on-peak/off-peak transmission reservations (firm or network 

transmission commitments) which have been stacked, or successively arranged, into an 

aggregated point-to-point transmission reservation longer than 28 days.”); id. P 369

(“[W]e clarify that the seller’s firm, network, and grandfathered transmission reservations 

longer than 28 days, including reservations for designated resources to serve retail load, 

shall be fully accounted for in the simultaneous import limit study.”); Order No. 697-A, 

FERC Stats. & Regs. ¶ 31,268 at P 142 (“[W]e clarify that the use of simultaneous TTC 

in the SIL study must properly account for all firm transmission reservations, 

transmission reliability margin, and capacity benefit margin.”). 

v

See generally Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 144 

(“Therefore, we will require applicants to allocate their seasonal and longer transmission 

reservations to themselves from the calculated SIL, where seasonal reservations are 

greater than one month and less than 365 consecutive days in duration, as defined in the 

Commission’s EQR Data Dictionary.”); Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 

at P 6 “[T]he Commission clarifies and reaffirms that it will require applicants to allocate 

their seasonal and longer transmission reservations to themselves from the calculated 

simultaneous transmission import limit only up to the uncommitted first-tier generation 

capacity owned, operated or controlled by the seller and its affiliates.”). 

vi See generally CP&L Clarification Order, 129 FERC ¶ 61,152 at P 26 (“We clarify 

that seasonal, historical peak load is one limitation on the SIL values reported in the 

indicative screens and the Delivered Price Test. This SIL value limitation applies to both 

scaling methodologies when conducting a SIL study (load-shift and generation-shift 

methodologies).” (footnote omitted)); id. P 26 n.16 (“The other two limitations are: (1) 

when transmission equipment reaches an operating limit during the energy transfer 

calculation portion of the SIL study (these are ‘the real-life physical limitations of firsttier balancing authority areas that impede power flowing from remote first-tier resources 

into the seller’s study area’; and (2) when the available uncommitted generation in the 

first-tier area is exhausted and no transmission equipment has reached an operating limit 

during the scaling process.” (citations omitted)).

Here, enter the highest hourly net energy for load value for each season from FERC Form 

No. 714 or equivalent and identify the source of the data if not FERC Form No. 714. Do 

not enter the average seasonal peak load value used in the wholesale market share screen 

because it is not the single, highest hourly load recorded for each season. 
Docket No. RM14-14-000 257

vii Puget Sound Energy, Inc., 135 FERC ¶ 61,254, at P 16 (2011) (“The transmission 

capability associated with these study area import reservations also must be subtracted 

from the study area’s native load to accurately represent the amount of study area native 

load available to being served by first-tier area generation when the study area native load 

limits the calculated SIL value. For example, PGE’s calculated SIL values exceeded its 

peak load in each season, so PGE correctly limited its SIL values to peak load. PGE then 

subtracted its affiliated long-term firm transmission reservations from its seasonal peak 

load to derive its adjusted or net SIL values, which it used in its updated market power 

analysis. PGE’s calculation appropriately limited its SIL values to the amount of its 

study area load open to competition from non-affiliated, first-tier generators.” (footnotes 

omitted)).

viii See generally April 14 Order, 107 FERC ¶ 61,018 at Appendix E (“[T]he 

applicant shall scale up available generation in the exporting (aggregated first tier 

areas)....”); CP&L Clarification Order, 129 FERC ¶ 61,152 at P 26 & n.16. 

ix See generally Public Service Company of New Mexico, 133 FERC ¶ 61,031 at P 

12-13 (accepting SIL values limited by peak load and reduced by amount of transmission 

reservations allocated to transmission owners’ remote resources brought into the study 

area to serve native load); AEP, 131 FERC ¶ 61,146 at P 13 (“Because each of the SPP 

Transmission Owners was to subtract its own reservations in calculating its final SIL 

values, this value should account for the largest quantity of transmission reservations into 

the study area, thus providing a reasonable estimate of remaining import capability to use 

in the preliminary market power screens.”); CP&L Clarification Order, 129 FERC ¶ 

61,152 at P 26 (“The SIL value reported in the indicative screens and the Delivered Price 

Test, however, cannot exceed the seasonal historical peak load value.”).
Docket No. RM14-14-000 258

Appendix F

List of Commenters and Acronyms

Commenter Short Name/Acronym

American Antitrust Institute AAI

American Electric Power Service 

Corporation AEP

American Public Power Association 

and National Rural Electric 

Cooperative Association APPA/NRECA

Avista Corporation and Puget 

Sound Energy, Inc. Avista/Puget

Barrick Goldstrike Mines Barrick

Romkaew Broehm and Gerald A. 

Taylor Broehm/Taylor

E.ON Climate & Renewables North 

America LLC E.ON

Edison Electric Institute EEI

El Paso Electric Company El Paso

Electric Power Supply Association EPSA

FirstEnergy Service Company FirstEnergy

Golden Spread Electric Cooperative, 

Inc. Golden Spread

Idaho Power Company Idaho Power Company

Indicated Western Utilities (Arizona 

Public Service Company; Idaho Indicated Utilities
Docket No. RM14-14-000 259

Power Company; NV Energy, Inc.; 

PacifiCorp; and Portland General 

Electric Company)

National Hydropower Association NHA

NextEra Energy, Inc. NextEra

Potomac Economics, Ltd. Potomac Economics

Southeast Transmission Owners 

(Duke Energy Carolinas, LLC; 

Duke Energy Progress, Inc.; 

Louisville

Gas and Electric Company and 

Kentucky Utilities Company; South 

Carolina Electric & Gas

Company; and Southern Company 

Services, Inc., acting as agent for 

Alabama

Power Company, Georgia Power 

Company, Gulf Power Company 

and Mississippi Power

Company) Southeast Transmission Owners

Southern California Edison 

Company SoCal Edison

Julie R. Solomon and Matthew E. 

Arenchild Solomon/Arenchild

SunEdison Inc. SunEdison

NRG Companies (over 120 entities 

wholly or partially owned 

subsidiaries of NRG Energy, Inc.) NRG Companies

Transmission Access Policy Study 

Group TAPS