147 FERC ¶ 61,232

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM14-14-000]

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

Electric Energy, Capacity and Ancillary Services by Public Utilities

(Issued June 19, 2014)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of Proposed Rulemaking.

SUMMARY: The Federal Energy Regulatory Commission (Commission) is proposing 

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

Regulations governing market-based rates for public utilities pursuant to the Federal 

Power Act (FPA). The Commission is proposing to revise its current standards for 

market-based rates for sales of electric energy, capacity, and ancillary services to 

streamline certain aspects of its filing requirements to reduce the administrative burden 

on applicants and the Commission. The Commission seeks comment on the proposed 

revisions. In addition, the Commission provides some clarification regarding the 

standards for obtaining and retaining market-based rate authority.

DATES: Comments are due [INSERT DATE 60 days after publication in the FEDERAL 

REGISTER].

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

ways: 
Docket No. RM14-14-000 2

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

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

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

comments to: Federal Energy Regulatory Commission, Secretary of the 

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

Instructions: For detailed instructions on submitting comments and additional 

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

document.

FOR FURTHER INFORMATION CONTACT:

Joseph Cholka (Technical Information)

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

202-502-8876

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:
Docket No. RM14-14-000

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Refinements to Policies and Procedures for MarketBased Rates for Wholesale Sales of Electric Energy, 

Capacity and Ancillary Services by Public Utilities

Docket No. RM14-14-000

NOTICE OF PROPOSED RULEMAKING

TABLE OF CONTENTS

Paragraph Numbers

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

II. Background.................................................................................................................. 2

III. Discussion ................................................................................................................. 31

A. Horizontal Market Power ...................................................................................... 31

1. Sellers in RTOs.................................................................................................. 31

2. Sellers with Fully-Committed Long-Term Generation Capacity...................... 41

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

Authority Areas ......................................................................................................... 47

4. Reporting Format for the Indicative Screens .................................................... 58

5. Competing Imports............................................................................................ 66

6. Capacity Ratings................................................................................................ 68

7. Reporting of Long-Term Firm Purchases.......................................................... 73

B. Vertical Market Power – Land Acquisition Reporting ......................................... 87

1. Current Policy.................................................................................................... 87

2. Proposal ............................................................................................................. 89

C. Notices of Change in Status .................................................................................. 93

1. Geographic Focus.............................................................................................. 94

2. Long-Term Contracts ........................................................................................ 99

3. New Affiliation and Behind-the-Meter Generation ........................................102

D. Asset Appendix....................................................................................................110

1. Current Policy..................................................................................................110

2. Proposal ...........................................................................................................111

E. Category 1 and Category 2 Sellers......................................................................128

1. Current Policy..................................................................................................128

2. Proposal ...........................................................................................................130

F. Corporate Families ..............................................................................................135

1. Corporate Organizational Charts.....................................................................135
Docket No. RM14-14-000 2

2. Single Corporate Tariff....................................................................................141

G. Clarification of Commission Language in Performing SIL Studies ...................144

1. Current Policy..................................................................................................144

2. Proposal ...........................................................................................................157

H. Parts 101 and Part 141 Waivers...........................................................................175

1. Current Policy..................................................................................................175

2. Proposal ...........................................................................................................176

I. Miscellaneous......................................................................................................179

1. Regional Reporting Schedule ..........................................................................179

2. Affirmative Statement .....................................................................................181

IV. Information Collection Statement .......................................................................182

V. Environmental Analysis......................................................................................193

VI. Regulatory Flexibility Act...................................................................................194

VII. Comment Procedures...........................................................................................204

VIII. Document Availability ........................................................................................208
Docket No. RM14-14-000

147 FERC ¶ 61,232

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Refinements to Policies and Procedures for MarketBased Rates for Wholesale Sales of Electric Energy, 

Capacity and Ancillary Services by Public Utilities

Docket No. RM14-14-000

NOTICE OF PROPOSED RULEMAKING

(Issued June 19, 2014)

I. Introduction

Pursuant to sections 205 and 206 of the Federal Power Act (FPA),11. the 

Commission is proposing to amend 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. 

II. Background

2. 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 

 

1

16 U.S.C. 824d, 824e (2012).
Docket No. RM14-14-000 2

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.

3. In April 2004, the Commission initiated a rulemaking proceeding to consider the 

adequacy of its market-based rate analysis and whether and how it should be modified to 

assure that prices for electric power being sold under market-based rates are just and 

reasonable under the FPA.2 At that time, the Commission noted that much had changed 

in the industry since its analysis was first developed and posed a number of questions that 

would be explored through a series of technical conferences. Following the technical 

conferences, the Commission issued a notice of proposed rulemaking that led to the 

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

market-based rate policy.3

4. In Order No. 697, the Commission adopted two indicative screens for assessing 

horizontal market power: the pivotal supplier screen and the wholesale market share 

 

2 Market-Based Rates for Public Utilities, 107 FERC ¶ 61,019, at P 1 (2004) 

(initiating rulemaking proceeding).

3 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 3

screen (with a 20 percent threshold), each of which serves as a cross check on the other to 

determine whether sellers may have market power and should be further examined.4 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 through a delivered price test (DPT) analysis 

demonstrating that, despite a screen failure, they do not have market power.5 The 

Commission uses a “snapshot in time” approach based on historical data for both the 

indicative screens and the DPT analysis.6

5. With respect to the horizontal market power analysis, in traditional markets 

(outside regional transmission organization/independent system operator (RTO/ISO)

markets),7the 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 

 

4 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 62.

5

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

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

7 We will use the term “RTO” when referring to either an RTO or ISO for easier 

readability.
Docket No. RM14-14-000 4

balancing authority areas).8 Generally, sellers that are located in and are members of the 

RTO may consider the geographic region under the control of the RTO 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 

 

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.

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

within an RTO, 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.
Docket No. RM14-14-000 5

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 § 35.42 of the Commission’s regulations to require 

market-based rate sellers 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 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 clarified 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.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 

 

12 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 176.

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. 
Docket No. RM14-14-000 6

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 

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

In Order No. 697, the Commission created two categories of sellers.20 8. Category 1 

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

500 megawatts (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 

 

16 18 CFR 35.39.

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.
Docket No. RM14-14-000 7

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 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 

 

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).

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 8

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 

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

manipulation, and take steps to remedy any violations.25

10. As discussed below, after over six years of experience with the implementation of

Order No. 697, we propose certain changes and clarifications in order to streamline and 

simplify the market-based rate program, and to enhance and improve the program’s 

processes and procedures. Based on our experience, we have found that the burdens 

associated with certain of our requirements may outweigh the benefits in certain 

circumstances. For these reasons, we propose a number of changes to the market-based 

rate program which, taken as a whole, will 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. 

We also include several specifications and propose a number of minor changes that will 

add clarity to, and improve transparency in, the market-based rate program.

 

25 Id. P 5.
Docket No. RM14-14-000 9

Summary of Proposals

11. Although we intend to retain the horizontal indicative screens, we propose certain 

modifications to our horizontal market power analysis. First, we propose to allow sellers 

in RTO markets to address horizontal market power issues in a streamlined manner that 

would not involve the submission of indicative screens if the seller relies on 

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

power. We also propose to clarify that where all generation capacity owned or controlled

by a seller and its affiliates in the relevant balancing authority areas (including first-tier 

balancing authority areas or markets) is fully committed, sellers may explain that their 

capacity is fully committed in lieu of submitting indicative screens as part of their 

horizontal market power analysis.

12. While we are retaining the definition of the default geographic market for the vast 

majority of sellers, we are proposing a redefined default relevant geographic market for 

an independent power producer (IPP) with generation capacity located in a generationonly balancing authority area. We propose that, instead of the default geographic market 

being the generation-only balancing authority area where its generation is located, the 

IPP’s default geographic market(s) will be the balancing authority area(s) of each 

transmission provider to which the generation-only balancing authority area is directly 

interconnected.

13. In Order No. 697, the Commission adopted standard indicative screen formats for 

submitting a horizontal market power analysis. We propose to add rows to the indicative 
Docket No. RM14-14-000 10

screen format for sellers to specify Simultaneous Transmission Import Limit (SIL) 

Values, Long-Term Firm Purchases (from outside the study area), and Remote Capacity 

(from outside the study area), as well as modifications to the descriptive text of the rows 

to make them more consistent. We further propose to revise the regulations to require 

that sellers file the indicative screens in a workable electronic spreadsheet format. We 

also propose to revise the Commission’s regulations to codify the requirement, first 

discussed in Puget Sound Energy, Inc.,

26 that sellers submitting SIL studies adhere to the 

direction and required format for Submittals 1 and 2 found on the Commission’s Web site 

and that sellers submit Submittals 1 and 2 in a workable electronic spreadsheet format.

14. The Commission previously stated that sellers could make simplifying 

assumptions such as “performing the indicative screens assuming no import capacity.” 

We clarify that “assuming no import capacity” means a seller may assume that there is no 

competing import capacity from the first-tier balancing authority areas or markets.

15. The Commission generally permits sellers submitting indicative screens to rate 

their generation facilities using either nameplate or seasonal capacity ratings. In addition, 

the Commission allows sellers with energy-limited resources, such as hydroelectric and 

wind generation facilities, to use a five-year average capacity factor. We propose to 

include solar technologies as energy-limited generation resources. We further propose 

that sellers with energy-limited resources that do not have five years of historical data 

 

26 Puget Sound Energy, Inc., 135 FERC ¶ 61,254, Appendix B (2011) (Puget). 
Docket No. RM14-14-000 11

may use regional capacity factor estimates appropriate to the specific technology as 

derived by the United States Energy Information Administration (EIA) to determine the 

capacity for those resources. We also propose to clarify that a seller must use the same

capacity rating methodology for similar generation assets throughout a particular filing.

16. The Commission has stated that a seller’s uncommitted capacity is determined by 

adding the nameplate or seasonal capacity of generation owned or controlled through 

contract and long-term firm capacity purchases, less operating reserves, native load 

commitments, and long-term firm sales. Therefore, sellers have been reporting their 

long-term firm purchases as part of their capacity if the purchase granted them control of 

that capacity. We propose to require sellers to report 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. This approach will help size the market correctly and will establish 

consistent treatment of long-term firm sales and long-term firm purchases.

17. The Commission’s vertical market power analysis examines affiliation, ownership 

or control of inputs to electric power production, including sites for generation capacity 

development. In this Notice of Proposed Rulemaking (NOPR), we propose to eliminate 

the requirement that sellers provide information on sites for generation capacity 

development in their market-based rate applications and triennial updated market power 

analyses and to similarly relieve sellers of their obligation to file quarterly land 

acquisition reports.
Docket No. RM14-14-000 12

18. The Commission requires that sellers report to the Commission any change in 

status that would reflect a departure from the characteristics the Commission relied upon 

in granting market-based rate authority. We propose to revise the regulations to clarify

that the 100 MW reporting threshold for filing a notice of change in status is not limited 

to markets previously studied; thus if a seller acquires generation that causes a 

cumulative net increase of 100 MW or more in any relevant geographic market, the seller 

must file a notice of change in status. We also propose to revise the regulations to 

include long-term firm purchases of capacity and/or energy in calculating the 100 MW 

change in status threshold. Although there currently is no threshold for reporting a 

change in status that results in a new affiliation, we propose to revise the regulations to 

include a 100 MW threshold for reporting new affiliations.

19. The Commission requires that sellers include with each new application, market 

power analysis, and relevant change in status notification an asset appendix that lists all 

affiliates that have market-based rate authority and identifies assets owned or controlled 

by the seller and its affiliates. We propose to revise the asset appendix by revising the 

headings of several columns to be more clear and consistent. We also propose several 

clarifications to the asset appendix requirements. In particular: (1) a seller must enter the

entire amount of a generator’s capacity, even if the seller only owns part of the generator; 

(2) a seller must list one of three specified uses for assets in the asset list containing 

electric transmission and intrastate gas assets; and (3) sellers should not list assets in 

which passive ownership interests have been claimed. We also propose to modify the 
Docket No. RM14-14-000 13

asset appendix to add a new column in the list of transmission assets for the citation to 

the Commission order accepting the OATT or granting waiver of the OATT requirement. 

We further propose to require that sellers submit the asset lists in an electronic 

spreadsheet format that can be searched, sorted, and accessed using electronic tools. We 

also seek comment on whether it would be useful to develop a comprehensive searchable 

public database of the information contained in the asset appendix, which sellers could 

access to update their asset appendices.

20. There are two categories of market-based rate sellers. Category 1 sellers are 

exempt from the requirement to automatically submit updated market power analyses 

every three years. Market-based rate Category 2 sellers are required to submit an updated 

market power analysis every three years according to a regional schedule. We include an 

updated schedule and region map as part of this NOPR.

21. One of the criteria that must be satisfied to be a Category 1 seller in a region is that 

the seller and its affiliates must own or control 500 MW or less of generation in aggregate 

in that region. We propose to codify in the Commission’s regulations a distinction in 

determining seller category status for power marketers and power producers. For each 

region, a power marketer should include all affiliated generation in that region, while a 

power producer would only need to include affiliated generation capacity that is located 

in the same region as the power producer’s generation asset(s). We propose this

difference in treatment based on the fact that a power marketer is assumed to have no 
Docket No. RM14-14-000 14

home market, while it is assumed that a majority of a power producer’s sales will be in 

market(s) in which it owns generation assets.

22. While sellers have been required to describe their affiliates and upstream owners 

when filing initial applications, updated market power analyses and notices of change in 

status involving new affiliations, we propose to add a requirement in the regulations that 

sellers provide an organizational chart as well. We propose that the organizational chart 

be similar to that which we require from FPA section 203 applicants.

23. Although we have previously explained that joint filers are permitted to designate 

one market-based rate seller to file a single, joint master corporate market-based rate

tariff for inclusion in the Commission’s eTariff database that reflects the joint tariff for all 

affiliated sellers, many sellers have not taken advantage of the option to file a joint master 

corporate market-based rate tariff. We propose to clarify on the Commission’s Web site 

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.

24. We also propose to provide clarification regarding several issues related to how to 

perform SIL studies and regarding the associated Submittals 1 and 2. In particular, we 

propose to clarify issues relating to what is meant by Open Access Same-Time 

Information System (OASIS) practices, how to deal with conflicts between OASIS 

practices and Commission direction provided in Appendix B of Puget, and what is the 

correct load value to use in the SIL study.
Docket No. RM14-14-000 15

25. The Commission has previously stated that the methodology a transmission 

provider uses to calculate SIL values must be consistent with the methodology it uses for 

calculating and posting available transmission capability (ATC) and for evaluation of 

firm transmission service requests. We propose to clarify that “OASIS practices” refers 

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. We further propose to clarify that in performing a SIL study, the

transmission provider must follow its OASIS practices consistent with the administration

of its tariff. Thus, 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. We clarify that where there 

is a conflict between the transmission provider’s tariff or OASIS practices and the 

Commission’s directions in Puget, sellers should follow OASIS practices except where 

use of actual OASIS practices is incompatible with an analysis of import capability from 

an aggregated first-tier area. We also remind sellers that the calculated SIL value should 

account for any limits defined in the tariff, such as stability or voltage. We reiterate that 

sellers may use load scaling to perform a SIL study if they use load scaling in their 

OASIS practices as long as they submit adequate support and justification for the scaling 

factor used and how the resulting SIL value compares had the seller used a generationshift methodology. We also instruct sellers to subtract all long-term firm import 
Docket No. RM14-14-000 16

transmission reservations, including reservations held by non-affiliated sellers, from the 

simultaneous total transfer capability (simultaneous TTC) value. Finally, we clarify that 

the seller should reduce the simultaneous TTC value by subtracting all wheel through 

transactions used to serve non-affiliated load embedded in the study area using first-tier 

area generation. These transactions should be accounted for as long-term firm 

transmission reservations and reported in Submittal 2.

26. We propose to amend Submittal 1 to revise Row 8 to read “Adjusted Historical 

Peak Load” and propose to direct sellers to include all load associated with the balancing 

authority area(s) within the study area, including non-affiliated load. Submittal 1 requires 

sellers to use FERC Form No. 714 load values or explain the source of the data used. We 

seek comment on the appropriate source of historical peak load data.

27. We propose to clarify that where a first-tier market or balancing authority area is

directly connected to the study area only by controllable tie lines and is not connected to 

any other first-tier market or balancing authority area, sellers should follow their OASIS 

practice regarding calculation and posting of ATC for such areas. If the seller’s OASIS 

practices are incompatible with the SIL study, entities may use an alternative process to 

account for import capability for such tie lines.

28. We propose to provide standard guidance for data submittals and representations 

that sellers using the simultaneous TTC must provide, including historical data of actual, 

hourly, real-time TTC values used for operating the transmission system and posting 

availability on OASIS for each interface during each seasonal study period. We propose 
Docket No. RM14-14-000 17

to clarify that sellers may use the maximum sum of TTC values for any day and time 

during each season as long as they demonstrate that these TTC values are simultaneously 

feasible. Finally, we reiterate that, if there are limited interconnections between first-tier 

markets, we will review evidence that potential loop flow between first-tier areas is 

properly accounted for in the underlying SIL values and we clarify 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.

29. We note that there are certain waivers that the Commission has granted to certain 

sellers with market-based rate authority, e.g., power marketers and independent or 

affiliated power producers, such as waiver of the Uniform System of Accounts 

requirements, specifically waiver of Parts 41, 101, and 141 of the Commission’s 

regulations except §§ 141.14 and 141.15. We clarify that any waiver of Part 101 granted 

to a market-based rate seller is limited such that waiver of the provisions of Part 101 that 

apply to hydropower licensees is not granted with respect to licensed hydropower 

projects. The Commission further directs that, to the extent that a 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 be granted with respect to licensed hydropower projects. Similarly, 

hydropower licensees that have been granted waiver of Part 141 as part of their market-
Docket No. RM14-14-000 18

based rate authority should ensure that the limitations and exemptions section of their

market-based rate tariffs specify that waiver of Part 141 has been granted, with the 

exception of §§ 141.14 and 141.15.

30. The Commission’s regulations require as part of the vertical market power 

analysis that sellers 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. 

We propose to revise the regulations to make it clear that the obligation to make the 

affirmative statement applies to both the seller and its affiliates.

III. Discussion

A. Horizontal Market Power

1. Sellers in RTOs

a. Current Policy

31. 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 a seller studying an RTO as 

a relevant geographic market (RTO seller) fails the indicative screens for the RTO, it can 
Docket No. RM14-14-000 19

seek to obtain or retain market-based rate authority by relying on Commission-approved 

RTO monitoring and mitigation.27

32. In 2001, the Commission originally proposed that all sales, including bilateral 

sales, into an RTO with Commission-approved market monitoring and mitigation would 

be exempt from the generation market power analysis in effect at that time (the Supply 

Margin Assessment test) and, instead, would be governed by the specific thresholds and 

mitigation provisions approved for the particular market.28 However, the Commission 

subsequently concluded that it would no longer exempt sellers located in markets with 

Commission-approved market monitoring and mitigation from providing generation 

market power analyses, on the basis that requiring sellers located in such markets to 

submit indicative screens provides an additional check on the potential for market 

power.

29

 

33. In Order No. 697, the Commission declined the request that it reinstate the prior 

RTO exemption, stating it “will continue to require generation market power analyses 

 

27 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] market monitoring and mitigation, we 

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

market power concerns.”

28 AEP Power Marketing, Inc., 97 FERC ¶ 61,219, at 61,970 (2001).

29 AEP Power Marketing, Inc., 107 FERC ¶ 61,018, at P 186 (April 14, 2004

Order), order on reh’g, 108 FERC ¶ 61,026 (2004). 
Docket No. RM14-14-000 20

from all sellers, including those in [RTO] markets.”30 In Order No. 697-A, the 

Commission denied requests to reconsider its decision stating that 

the dual protections of individual market power analyses and mitigation 

rules of the [RTOs] provide the Commission with better ability to discern 

and protect against potential market power. While, as discussed below, 

mitigation rules for the individual [RTOs] in most cases should be 

sufficient to guard against the exercises of market power, we are not 

comfortable at this time with dispensing of the requirement for sellers in 

[RTOs] to provide us with horizontal market power analyses. Any 

administrative burden of submitting such analyses is outweighed by the 

additional information gleaned with respect to a specific seller’s market 

power.[

31] 

34. Since the issuance of Order No. 697, it has been the Commission’s practice to 

grant sellers market-based rate authority or allow them to retain market-based rate 

authority where they have failed indicative screens in an RTO but have relied on 

Commission-approved monitoring and mitigation.32 RTO sellers are sellers that study an 

 

30 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 290. 

31 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 110.

32 See, e.g., Niagara Mohawk Power Corp., 123 FERC ¶ 61,175, at P 28 (2008) 

(failures in the New York City and Long Island submarkets of the New York Independent 

System Operator, Inc.); Dominion Energy Marketing, Inc., 125 FERC ¶ 61,070, at 

PP 26-27 (2008) (failures in the Connecticut submarket of ISO New England, Inc.); 

PSEG Energy Resources & Trade LLC, 125 FERC ¶ 61,073, at PP 31-32 (2008) (failures 

in the PJM-East submarket). There are also numerous delegated letter orders granting a 

seller market-based rate authority where the seller relies on Commission-approved 

monitoring and mitigation in RTO markets. See, e.g., TransCanada Energy Marketing 

ULC, Docket No. ER07-1274-001 (Jan. 23, 2009) (delegated letter order). Finally, the 

Commission has not initiated any investigations pursuant to section 206 of the FPA for 

any RTO sellers failing indicative screens since the issuance of Order No. 697; in all

 (continued...)
Docket No. RM14-14-000 21

RTO as a relevant geographic market, including those that sell bilaterally. While the 

burdens of preparing the indicative screens are not necessarily greater for RTO sellers 

than for sellers in other markets, the submission of indicative screens yields little 

practical benefit since it has been the Commission’s practice to allow RTO sellers that 

fail the indicative screens to rely on RTO monitoring and mitigation. Thus, for sellers in 

RTOs, the burden of submitting indicative screens may not be “outweighed by the 

additional information gleaned with respect to a specific seller’s market power.”33

b. Proposal

35. We propose to modify the approach taken in Order No. 697 to reflect current 

practice and reduce the burden on these sellers. Specifically, we propose to allow 

market-based rate sellers in RTO markets with Commission-approved monitoring and 

mitigation to address horizontal market power issues in a streamlined manner when

submitting initial applications requesting market-based rate authority and updated market 

power analyses. We note that this proposal includes RTO sellers who may have bilateral 

contracts not subject to the Commission-approved monitoring and mitigation. We find 

that the existence of monitoring and mitigation in an organized market generally results

 

cases where RTO sellers failed, the Commission relied on the Commission-approved 

monitoring and mitigation to prevent the seller’s ability to exercise any potential market 

power. 

33 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 110.
Docket No. RM14-14-000 22

in a market where prices are transparent.34 This disciplines forward and bilateral markets 

by revealing a benchmark price and keeping offers competitive. For example, if a seller 

offers what a buyer perceives as a non-competitive price in the bilateral market, that 

buyer can opt to purchase in the spot market. This provides a strong incentive for the 

seller to offer at a competitive price in the forward and bilateral markets.

36. Under this streamlined approach, RTO sellers would not have to submit indicative 

screens as part of their horizontal market power analyses if they rely on Commissionapproved monitoring and mitigation to prevent the exercise of market power. Rather, to 

address horizontal market power effects, RTO sellers instead would simply state that they 

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

and provide an asset appendix and describe their generation and transmission assets. 

Under this proposal, all RTO sellers seeking market-based rate authority in an RTO 

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. To address horizontal market power 

effects, both the initial applications for market-based rate authorization and the updated 

market power analyses would include: (1) a statement that the seller is relying on RTO 

mitigation to address any potential market power it might have; (2) identification and 

 

34 April 14 Order, 107 FERC ¶ 61,018 at P 189.
Docket No. RM14-14-000 23

description of generation and transmission assets; and (3) an asset appendix.35 In all 

scenarios, the Commission would retain the ability to require an updated market power 

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

37. Thus, we propose to add a paragraph to the end of § 35.37(c) (regarding horizontal 

market power), making it paragraph (6) under this subsection, to read as follows: 

In lieu of submitting the indicative screens, Sellers in regional transmission 

organization and independent system operator markets with Commissionapproved market monitoring and mitigation must include a statement that they are 

relying on such mitigation to address any potential horizontal market power 

concerns.

38. In addition, we note that market-based rate sellers are not required by Order 

No. 697 or the regulations to provide indicative screens in their horizontal market power 

analyses when submitting change in status filings.36 In Order No. 697-A, the 

Commission stated:

The existing [change in status] reporting requirement provides the 

Commission a sufficient tool to allow it to assess whether there is a 

 

35 Applicants making these filings would continue to be required to provide the 

following information that is related to the non-horizontal market power issues: (1) a 

standard vertical market power analysis; (2) category status representations; (3) a 

demonstration that sellers continue to lack captive customers in order to support 

obtaining or retaining a waiver of the affiliate restrictions, if requested; and (4) any other 

information that is required for that particular filing. 

36 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 506 (“[W]e will not 

require entities to automatically file an updated market power analysis with their change 

in status filings . . . . Furthermore, regardless of the seller’s representation, if the 

Commission has concerns with a change in status filing (for example, market shares are 

below 20 percent, but are relatively high nonetheless), the Commission retains the right 

to require an updated market power analysis at any time.”).
Docket No. RM14-14-000 24

potential market power concern and, if so, the Commission reserves the 

right to require the seller to submit a market power study. In addition, the 

seller is required to provide an affirmative statement as to what effect, if 

any, the added generation has on its market power. For a seller to make 

such an affirmative statement, it must determine what effect the added 

generation has on the market power analysis. To the extent the seller 

makes an affirmative statement that there is no effect on its market power, 

it is bound to that statement and faces remedial action, including civil 

penalties, if it has misrepresented the effect.[

37]

39. Historically, when a change in status filing has created the likelihood that a seller 

would fail an indicative screen, the seller has often voluntarily submitted indicative 

screens in order to determine the effect of the change on its market power. We clarify

that, with this proposed streamlined approach, an RTO seller need not submit indicative 

screens with its change in status filing even where it may have market power. Instead,

the seller may state that it is relying on Commission-approved monitoring and mitigation 

to mitigate any potential market power it may have. However, the Commission still 

reserves the right to require an updated market power analysis at any time. 

40. We seek comment on this proposal. 

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

a. Current Policy

41. 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 

 

37 Id. P 505 (emphasis added).
Docket No. RM14-14-000 25

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

No. 697-A, the Commission stated: 

once capacity is committed long-term, regardless of how that capacity is 

priced (e.g., whether linked to spot prices or not), the ability of the firm to 

use that capacity to exercise market power in the spot market is severely 

limited or non-existent. The ability to collude will be determined by the 

remaining uncommitted capacity in the spot market, not the capacity that is 

already committed under long-term contracts. Therefore, we conclude that 

it is appropriate to subtract capacity committed under long-term contracts 

when calculating a seller’s uncommitted capacity for purposes of 

performing the indicative screens.[

38] 

42. Thus, the capacity dedicated to long-term firm power sales should be deducted 

from seller and affiliate capacity in Row C (Long-Term Firm Sales) of the standard 

screen format provided in Appendix A to Subpart H of Part 35 for submitting the 

indicative screens.39 However, some sellers have filed indicative screens in which they

did not deduct their fully-committed capacity or incorrectly reported capacity as fully 

committed when it was only committed for some seasons, for less than one year, or under 

certain market conditions.

40

 Moreover, some sellers have argued that there is no need to 

 

38 Id. P 41. 

39 18 CFR 35.37(c)(4). We note 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. See Order No. 697-A, 

FERC Stats. & Regs. ¶ 31,268 at n.6. We propose to amend Appendix A to Subpart H of 

Part 35 to add the market share screen that was inadvertently removed and to make 

proposed changes to both indicative screens as discussed herein.

40 The EQR data dictionary defines firm power sales as sales that are noninterruptible for economic reasons and states that contracts with durations of one year or 

greater are long-term. 
Docket No. RM14-14-000 26

perform indicative screens when they can demonstrate that all of their capacity is 

committed under long-term contract.

b. Proposal

43. It is the Commission’s policy to study uncommitted generation capacity in the 

indicative screens.41 Currently, the seller’s owned or controlled capacity in megawatts is 

entered into the indicative screens and the fully-committed long-term (one year or longer) 

capacity is then deducted. If all of the seller and its affiliates’ capacity in the relevant 

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

markets is fully committed, this exercise results in a purely mathematical task (netting to 

zero uncommitted capacity), thus providing no significant additional information. 

Therefore, we clarify 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. 

The Commission proposes to clarify that, in order to qualify as “fully committed,” a 

 

41 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 37-38; April 14, 2004

Order, 107 FERC ¶ 61,018 at P 71 (“We will adopt an uncommitted pivotal supplier 

analysis that will evaluate the potential of an applicant (including its affiliates) to exercise 

market power based on the control area market’s annual peak demand. We will also 

adopt an uncommitted market share analysis that will seasonally evaluate the market 

share of the uncommitted capacity of an applicant and its affiliates.”).
Docket No. RM14-14-000 27

seller must commit the capacity so that none of the excluded capacity is available to the 

seller or its affiliates for one year or longer. 

We propose that sellers claiming that all of their relevant capacity42 44. 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 longterm 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. Furthermore, 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). 

45. Finally, 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.

43

 

 

42 “Relevant” capacity refers to seller and affiliated capacity in the study area, 

including the first tier.

43 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). 
Docket No. RM14-14-000 28

46. We seek comment on these proposals. 

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

a. Current Policy

47. The Commission stated in Order No. 697 that “the horizontal market power 

analysis centers on and examines the balancing authority area where the seller’s 

generation is physically located”44 and that the default relevant geographic market 

(default 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 (firsttier balancing authority area markets).”45

 However, 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).”

46

 Similarly, the Commission continued to require 

RTO sellers “to consider, as part of the relevant market, only the relevant [RTO] market 

and not first-tier markets to the [RTO].”47

 

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

45 Id. P 232. 

46 Id. n.217.

47 Id. P 231 n.215.
Docket No. RM14-14-000 29

48. The Commission further stated in Order No. 697 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.”48 Order No. 697 rejected the concept of a “hub” as a relevant 

geographic market, noting that for purposes of evaluating market power, “trading hub 

data alone does not provide a foundation for the Commission to analyze transmission 

limitations and other transfers of energy.”49 However, Order No. 697 did not specifically 

address the default market for a seller located in a balancing authority area that has 

generation capacity but no load or customers (a generation-only balancing authority 

area). As discussed below, the Commission is concerned that the default market 

definition from Order No. 697 does not accurately reflect the market for all sellers, 

particularly in the Western Electricity Coordinating Council (WECC), which has several 

generation-only balancing authority areas with generation that is not sited close to load. 

 

48 Id. P 251. 

49 Id. P 275. We note that a number of hubs (e.g., Palo Verde, Four Corners, and 

Mead, etc.) are located at the intersections of clearly-defined balancing authority areas. 

Historically, identifying the market for generation located at the hub was not important 

because vertically-integrated utilities used their own generation to meet their load. As the 

markets have evolved, many hubs have become trading centers and some IPPs have built 

generation near hubs. The Commission has defined a trading hub as “a representative 

location at which multiple sellers buy and sell power and ownership changes hands, 

typically with trading of financial and physical products.” Id.
Docket No. RM14-14-000 30

49. The issue of what constitutes an appropriate market for an IPP in a generationonly balancing authority area has arisen because there is often no clear nexus between the 

default market, the generation resources an IPP competes with, and the customers an IPP 

actually serves.50 Since the implementation of Order No. 697, we have observed several 

instances in which the default market may not be appropriately defined for some IPPs in 

generation-only balancing authority areas.

51

 Moreover, the issue of proposing an 

appropriate geographic market for IPPs in generation-only balancing authority areas that 

do not serve load in the default market (i.e., their home balancing authority area) is 

further complicated when the IPP makes sales to a trading hub (e.g., Palo Verde). The 

following factors illustrate some differences between IPPs and franchised public utilities 

in terms of identifying the appropriate geographic markets.

50. Franchised public utilities typically have a geographically-defined franchised 

service territory and an obligation under state law to serve retail customers residing 

within that service territory.52 Thus, the home balancing authority area reflects the 

 

50 For 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 a 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.

51 See, e.g., Sundevil Power Holdings, LLC, Docket No. ER10-1777-000 (Sept. 15, 

2010) (delegated letter order). 

52 See 18 CFR 35.36(a)(5). A franchised public utility’s obligation to serve is 

modified, but not entirely eliminated, in states that have implemented “retail choice.”
Docket No. RM14-14-000 31

primary market in which a franchised public utility sells electricity, because this is where 

its customers are located. In addition, a franchised public utility’s generation capacity is 

usually dedicated primarily to serving load in its franchised service territory even though 

it may sell at least some wholesale power outside of its service territory. Therefore, the 

default market (home and first-tier balancing authority areas) is appropriate for 

franchised public utilities because there is a clear nexus between the physical location of 

a franchised public utility’s generation and the load served by that generation.

51. In contrast, an IPP does not have a franchised service territory, or an obligation to 

serve retail customers.53 Moreover, generation-only balancing authority areas do not 

have any load; therefore, these balancing authority areas do not appear to meet the 

Commission definition of a default market as they do not, by definition, “maintain[]

load/resource balance with the area.”54 IPPs may directly interconnect to transmission 

providers at energy trading hubs to facilitate sales to one or more markets within the 

broader region.

 

53 Thus, the Commission’s policy is to use the balancing authority area(s) (or 

RTO) where an IPP’s generation is physically located as the relevant geographic 

market(s). Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217. 

54 Id. P 251; see also NERC Glossary of Terms Used in NERC Reliability 

Standards 10 (2014) (“The collection of generation, transmission, and loads within the 

metered boundaries of the Balancing Authority. The Balancing Authority maintains 

load-resource balance within this area.”), 

http://www.nerc.com/files/glossary_of_terms.pdf.
Docket No. RM14-14-000 32

b. Proposal

52. In light of the unusual and complex circumstances identified above 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, we propose 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.55 Thus, if an IPP’s generation-only balancing authority area is directly 

interconnected with one or more balancing authority areas, the IPP would provide 

indicative screens for each of those balancing authority areas.

53. We further propose 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 in each market that is directly

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

not sold into that market in the past.

 

55 Consistent with the Commission’s proposal above in the section dealing with 

proposed new filing requirements for sellers in RTOs, the IPP would not need to study 

itself in any RTO market to which its generation-only balancing authority area is directly 

interconnected. Instead, the IPP must include a statement that it is relying on 

Commission-approved market monitoring and mitigation to address any potential 

horizontal market power concerns.
Docket No. RM14-14-000 33

54. To illustrate how this proposal would work, if an IPP is located in a generationonly 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 will provide indicative screens for that transmission provider’s 

balancing authority area. 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. 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. Thus, 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.

55. Similarly, if an IPP is located in a generation-only balancing authority area in a 

remote area such as the desert Southwest, then the Commission proposes that 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. We further propose that an IPP assume that all of its uncommitted 

capacity may compete in each balancing authority area to which its generation-only 
Docket No. RM14-14-000 34

balancing authority area is directly interconnected, since, as noted above, 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. Thus, for 

example, if it were the case that the generation-only balancing authority areas of the Gila 

River Power Company LLC and Sundevil generating 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 include all other competing generators from generation-only 

balancing authority areas directly interconnected with the APS balancing authority area 

in that study as well. These IPPs in generation-only balancing authority areas would also 

study themselves in the same manner in any other balancing authority areas to which 

their generation-only balancing authority area is directly interconnected.56 Consistent 

with what is proposed above, an IPP in this situation would not need to study any firsttier markets, just as would be the case if it were a generator located within the 

transmission provider’s home balancing authority area.

57

56. If an IPP in a generation-only balancing authority area is directly interconnected to 

a transmission provider at an energy trading hub, we propose that the IPP would provide 

 

56 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.

57 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 232 n.217.
Docket No. RM14-14-000 35

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 screens that study the IPP in each of those transmission 

providers’ balancing authority areas.58 Consistent with what is proposed above, we

propose that the IPP should 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.59 Thus, for example, 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,

60 then it would provide screens that study all of its 

 

58 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.

59 When providing screens for the directly interconnected balancing authority 

areas, the IPP would also include the uncommitted capacity of any other generation-only 

balancing authority area also interconnected to the same transmission providers at that 

hub. However, the transmission providers, in all cases, would consider the IPP 

generation capacity as first-tier generation when conducting their SIL studies and 

indicative screens.

60

 A generator interconnected to a transmission provider at a location where the 

transmission provider is directly interconnected to other transmission providers would 

also be directly interconnected to those other transmission providers. 
Docket No. RM14-14-000 36

uncommitted capacity in each balancing authority area that is directly interconnected at 

the switchyard. Also, consistent with what is proposed above, an IPP in this situation 

would not need to provide screens that study itself in any markets that are first tier to the 

various balancing authority areas that are directly interconnected at the switchyard.

57. We seek comment on these proposals. 

4. Reporting Format for the Indicative Screens

a. Current Policy

58. When submitting a horizontal market power analysis, sellers are required to use 

the standard screen format provided in Appendix A to Subpart H of Part 35 for 

submitting their indicative screens. Although sellers submit their indicative screens 

based on the formats provided in Appendix A to Subpart H of Part 35 and in Commission 

Order Nos. 69761 and 697-A,62 they currently perform their own mathematical 

calculations. The Commission does not currently provide pre-programmed spreadsheets 

that allow for automated mathematical calculations for sellers’ indicative screens. When 

preparing their screens, certain sellers also perform SIL studies, which produce data (e.g.,

SIL values) applicable to the indicative screens. 

 

61 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 305-306.

62 See Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 17 n.6, Appendix A.
Docket No. RM14-14-000 37

In Puget,

63 59. the Commission adopted a standardized format for reporting SIL study 

results in order to help ensure greater efficiency. The Commission directed sellers to 

refer to the guidance, directions, and reporting format provided in Appendix B of Puget 

when preparing and submitting SIL studies.64 Appendix B of Puget discusses various 

submittals, including “Submittal 1,” which is a spreadsheet that calculates the SIL values 

to be used in the indicative screens. Submittal 1 is a summary spreadsheet of the SIL 

components used to calculate the SIL values and is currently posted on the Commission’s 

Web site. The last line of Submittal 1 (Row 10) contains the SIL values that sellers 

should use in preparing their screens.65 Currently, the screen reporting format in 

Appendix A of Subpart H, which is discussed in Order Nos. 697 and 697-A, does not 

have a row for SIL values even though the Uncommitted Capacity Import values in the 

indicative screens are constrained by the SIL value from Row 10 of Submittal 1, i.e., the 

sum of the affiliated and non-affiliated Uncommitted Capacity Import values cannot 

exceed the SIL value.

66

 

 

63 Puget, 135 FERC ¶ 61,254 at Appendix B. 

64 Id. P 20.

65 Id. at Appendix B.

66 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 361 (explaining that a 

SIL study determines “how much competitive supply from remote resources can serve 

load in the study area.”).
Docket No. RM14-14-000 38

60. Appendix B of Puget also discusses “Submittal 2,” which is a spreadsheet that 

identifies long-term firm transmission reservations used to import power from seller and 

affiliate generating resources in the first-tier area to serve native load in the study area. 

The calculations performed in Submittal 2 provide detailed data summed to produce the 

total value of long-term firm transmission reservations, which are included in Row 5 of 

Submittal 1.

61. The Commission provided additional direction on the completion of the indicative 

screens in Vantage Wind Energy, LLC.

67 In particular, the Commission provided 

direction on how to account for both remote generation resources and long-term firm 

power purchases from generation resources located outside a seller’s home balancing 

authority area when performing the indicative screens.68 Currently, the indicative screen 

reporting formats in Appendix A of Subpart H and Order Nos. 697 and 697-A do not 

have separate rows for the value of installed capacity of remote generation resources or 

the capacity of resources that are external to the study area that support long-term firm 

 

67 Vantage Wind Energy, LLC, 139 FERC ¶ 61,063, at P 21 (2012) (Vantage 

Wind).

68 Id. (“[L]oad serving entities should add their share of remote generation to 

Installed Capacity (Line A of the market share screen and the pivotal market share 

screen) and the amount of any long-term firm purchases in ‘Long-term Firm Purchases’ 

(Line B of the market share screen and the pivotal supplier screen) of the indicative 

screens, when load-serving entities have long-term firm transmission rights associated 

with those resources.”). 
Docket No. RM14-14-000 39

power purchase agreements that serve load in the study area; both values are components 

of the SIL value used in the screens. 

b. Proposal

62. We propose to amend the indicative screen reporting format in Appendix A of 

Subpart H. We propose that Appendix A include both the pivotal supplier and market 

share screen reporting formats with new rows for SIL values, Long-Term Firm Purchases 

(from outside the study area), and Remote Capacity (from outside the study area). 

Including a row in the indicative screens for SIL value will help reinforce the relationship 

between the values for affiliated and non-affiliated capacity imports and the SIL value. 

For purposes of clarification, we also propose to modify the descriptive text of the rows 

in the indicative screens for Installed Capacity, Long-Term Firm Purchases, Long-Term 

Firm Sales, and Uncommitted Capacity Imports.

69 As discussed below, the new rows and 

their descriptions will clarify that 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. 

An example of the proposed new indicative screen reporting formats for Appendix A to 

Subpart H is provided in Appendix A of this NOPR.

 

69 We propose to change the phrase “Imported Power” in Rows D and H of the 

pivotal supplier screen to “Uncommitted Capacity Imports.” We also propose to make 

the same change to Row E of the Market Share Screen. Thus, 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.
Docket No. RM14-14-000 40

63. Additionally, we propose 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.

70

 The 

proposed new language is as follows:

When submitting a horizontal market power analysisthe 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 indicative screensform.

We propose to post on the Commission’s Web site a pre-programmed spreadsheet as an 

example that sellers may use to submit their indicative screens.

71

 The example 

spreadsheet contains pre-programmed cells that allow for summations and data 

comparisons, as well as cells that restrict entries to negative or positive values where 

appropriate. We believe that these proposed changes to the indicative screens, as 

reflected in Appendix A to this NOPR, will aid sellers when preparing screens and 

minimize the need for follow up inquiries from staff and amended filings.

 

70 “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. 

71 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 Web 

site. 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 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/docsfiling/elibrary/accept-file-formats.asp.
Docket No. RM14-14-000 41

64. We also propose to add a paragraph to the end of § 35.37(c), making it paragraph 

(5), to codify the requirement in Puget that sellers submitting SIL studies adhere to the 

direction and required format for Submittals 1 and 2 found on the Commission’s Web 

site72 and submit their information, as instructed, in workable electronic spreadsheets. 

The proposed new language is as follows:

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 Web site.

Revising the regulations to reflect this requirement will help ensure that sellers are aware 

of the requirement to include Submittals 1 and 2 in workable electronic spreadsheets as 

well.

73

 

65. We seek comment on these proposals.

 

72 The sample spreadsheets for Submittals 1 and 2 are found at the Commission’s 

Web site at http://www.ferc.gov/industries/electric/gen-info/mbr/authorization.asp under 

“Quick Links.”

73 Here, as with the indicative screens, 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 Web site. Specifically, it must have the same 

exact rows, columns, and descriptive text as the sample spreadsheet. Likewise, cells with 

calculated values must contain working formulas that calculate the value for that cell. 

Finally, the file must be submitted in one of the spreadsheet file formats accepted by the 

Commission for electronic filing. See FERC, Acceptable File Formats (January 2012), 

available at http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
Docket No. RM14-14-000 42

5. Competing Imports

a. Current Policy

66. The Commission permits sellers to make simplifying assumptions, where 

appropriate, and to submit streamlined horizontal market power analyses.74 In Order 

No. 697, the Commission stated 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.”75

b. Proposal

67. We clarify that the phrase “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 Order76 and other Commission orders.77 We further clarify that the seller must still 

 

74 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 308, 321; April 14, 

2004 Order, 107 FERC ¶ 61,018 at P 38.

75 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 321.

76 April 14, 2004 Order, 107 FERC ¶ 61,018 at P 38 (“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)).

77 See, e.g., Acadia Power Partners, LLC, 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 

both screens without considering competing supplies imported from adjacent control 

 (continued...)
Docket No. RM14-14-000 43

include any uncommitted capacity that it and its affiliates can import into the study area. 

We believe that this clarification will aid sellers when preparing screens and minimize 

the need for follow up inquiries from staff and amended filings. 

6. Capacity Ratings

a. Current Policy

68. The Commission allows sellers submitting indicative screens to rate their 

generation facilities using either nameplate or seasonal capacity ratings.78 With regard to 

sellers with energy-limited resources, such as hydroelectric and wind generation 

facilities, in lieu of using nameplate or seasonal capacity ratings in their submissions, the 

Commission stated in Order No. 697 that it would allow such sellers 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 

 

areas, the applicant need not include such imports.” (emphasis added) (footnote 

omitted)).

78 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 343 (“We will adopt the 

NOPR proposal that allows sellers to use seasonal capacity. We clarify that each seller 

must be consistent in its choice and thus must choose either seasonal or nameplate 

capacity and use it consistently throughout the analysis. In addition, a seller using 

seasonal capacity must identify in its submittal from what source the data was 

obtained.”). The Commission adopted the EIA definition of seasonal capacity as reported 

on Form EIA-860, Schedule 3, Part B, Line 2, which provides that seasonal capacity is 

the “‘net summer or winter capacity’” and EIA instructions that “‘net capacity should 

reflect a reduction in capacity due to electricity use for station service or auxiliaries.’” Id. 

(footnotes omitted).
Docket No. RM14-14-000 44

for the previous five years.79 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 for use in their analyses. To address this situation, the 

Commission has allowed the use of the five most recent years of regional average 

capacity factors from the EIA to determine capacity factors for those resources.80

b. Proposal

69. We recognize that there are energy-limited generation resources, such as solar 

photovoltaic and solar thermal facilities (collectively, solar technologies), which were not 

identified in Order No. 697. We propose to identify solar technologies as energy-limited 

generation resources and to allow such sellers to use either nameplate capacity or fiveyear historical average capacity ratings to determine the capacity rating for their solar 

technology generation resources, and, as noted above, sellers may use EIA regional 

average capacity factors for the previous five years to determine capacity for those 

resources. Similar to other energy-limited generation resources, sellers using the fiveyear historical average must include sensitivity tests using the lowest and highest capacity 

factors for the previous five years. We propose that sellers with energy-limited 

generation facilities (including those using solar technology) that do not have five years 

 

79 Id. P 344.

80 See Golden Spread Electric Coop., Inc., 138 FERC ¶ 61,208, at P 16 (2012) 

(Golden Spread) (finding that a five-year average wind capacity factor derived from EIA 

data represents an appropriate analysis). 
Docket No. RM14-14-000 45

of historical data may use the EIA-derived, regional capacity factor estimates appropriate 

to their specific technology as defined in the EIA publication Annual Energy Outlook.81 

We also propose to require that sellers without five years of historical data use either 

nameplate capacity or the EIA-derived, regional capacity factor estimates, but not 

seasonal ratings.

82

 For sellers using EIA-derived estimates, we propose to require that 

they 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. In addition, the Commission seeks industry input in identifying

additional technologies that are energy-limited generation resources, and what capacity 

factors should be used to rate them.

70. While we are proposing this treatment for solar capacity, we acknowledge that 

photovoltaic solar 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

 

81 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.

82 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 found 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. See Golden Spread, 138 FERC 

¶ 61,208 at P 16.
Docket No. RM14-14-000 46

energy from photovoltaic solar facilities during such conditions. Thus, we are seeking 

comment on whether it may make more sense to assign different capacity factors to solar 

generation as compared to other generation based on these operating characteristics. In 

particular, we seek comment on whether we should allow such sellers to use either 

nameplate capacity or five-year historical average capacity ratings during peak hours to 

determine the capacity rating for their solar technology generation resources, and, as 

noted above, sellers may use EIA regional average capacity factors over peak hours for 

the previous five years to determine capacity for those resources. In other words, we 

seek comment on whether using peak hours will provide a better measure of capacity for 

photovoltaic solar, as compared to all hours, which would necessarily include hours in 

which we can predict that output will be zero.

71. Finally, consistent with Order No. 697, we propose to clarify that, within each 

filing, a seller must use the same capacity rating methodology for similar generation 

assets.83 Specifically, 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 

 

83 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 343.
Docket No. RM14-14-000 47

those resources for which the seller does not have five years of data. 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. 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). We believe that when a seller consistently uses the same 

rating methodology within a filing, it will improve the accuracy of the horizontal market 

power analysis by linking the capacity values in the transmittal letter, accompanying 

testimony, generation asset appendix, and the indicative screens.

72. We seek comment on these proposals.

7. Reporting of Long-Term Firm Purchases

a. Current Policy

73. 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, less operating reserves, native load commitments, and long-term firm 
Docket No. RM14-14-000 48

sales.84 The Commission specified that 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, rather than to the entity that is the legal 

owner of the facility.85 Order No. 697 stated that if a market-based rate applicant has 

control over certain capacity, such that that applicant can affect the ability of the capacity 

to reach the market, then that capacity should be attributed to that applicant when 

performing the indicative screens.

86 As a result, in their initial and triennial market-based 

rate filings, market-based rate applicants87 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.88 Similarly, for purposes of reporting a 

change in status, market-based rate applicants have been required to report long-term 

 

84 Id. P 38. 

85 Id. P 157. 

86 Id. P 174. The Commission found that determination of control is based on a 

review of the totality of circumstances on a fact-specific basis. Id.

87 Although we generally use the term “market-based rate sellers” elsewhere in 

this NOPR, in this section we refer to such sellers as “market-based rate applicants” to 

avoid confusion when discussing sellers who are purchasers under long-term firm power 

purchase agreements.

88 Reflecting this capacity in Row B has the effect of attributing the capacity to the 

market-based rate applicant. 
Docket No. RM14-14-000 49

firm capacity purchases when assessing their cumulative generation capacity only if such 

purchases confer control of such capacity to the applicant purchaser.

89

 

74. This requirement also 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.

90

 In this regard, in Order No. 697-B, the Commission stated that if a contract 

for a fixed quantity of delivered energy does not confer control, it need not be reported.91 

The Commission stated its belief at that time that a long-term firm energy purchase by 

itself gives the purchaser only a right to receive energy and thus no rights that would 

allow the purchaser to control generation capacity, and that a determination of whether a 

long-term firm energy purchase confers control over generation capacity must be based 

on a review of the totality of the circumstances on a fact-specific basis.92 Many 

applicants under the market-based rate program, therefore, do not report some or all of 

 

89 Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at PP 99-101. 

90 Id.

91 Id. P 99.

92 Id. P 101. In Integrys Energy Group, Inc., 123 FERC ¶ 61,034 (2008), the 

Commission found that the sale of a “Firm (LD)” product, as defined in the EEI Master 

Power Purchase & Sale Agreement, by itself gives the purchaser only a right to receive 

energy and thus no rights that would allow the purchaser to control generation capacity. 

In reaching this determination, the Commission relied on the fact that the purchaser under 

a Firm (LD) product cannot force the seller to back down the output of any generator and 

the fact that if the purchaser refused to receive delivery, that refusal does not keep the 

power from entering the market because the seller has the right to resell the Firm (LD) 

product, as well as to receive damages from the purchaser.
Docket No. RM14-14-000 50

their long-term firm power purchases (including long-term firm energy purchases) in 

their indicative screens if they believe these purchases do not grant them control of the 

capacity. 

75. As explained below, we have determined, after two complete rounds of regional 

reviews, that the limited reporting of long-term firm purchases may create errors or 

misleading results in the indicative screens submitted by some sellers. These errors 

include 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. Specifically, on 

numerous occasions the Commission has encountered situations where neither the seller 

nor the purchaser under a long-term firm power sale is being attributed with the 

generation capacity that is used to make that sale. This is because the seller, consistent 

with Commission policy, has deducted the capacity committed under the long-term firm 

power sale93 for purposes of calculating that seller’s uncommitted capacity, while the 

purchaser has used our policies (and underlying assumptions) outlined above to assume 

that it is also not responsible for this capacity and therefore has not included this capacity 

as part of the purchaser’s uncommitted capacity. The combination of these actions by 

sellers and purchasers results in capacity under long-term firm power purchase 

 

93 The EQR Data Dictionary defines a firm sale as “a sale, service or product that 

is not interruptible for economic reasons.” See Filing Requirements for El. Utility S.A., 

Order Updating Electric Quarterly Report Data Dictionary, 146 FERC ¶ 61,169, 

Attachment (2014) (“EQR Data Dictionary Transaction Data” table, field number 59). 
Docket No. RM14-14-000 51

agreements many times “disappearing” from the market, with neither counterparty 

reflecting the capacity in their screens.

76. One result of this practice is that it leads to the anomalous result in the indicative 

screens of some franchised public utility sellers appearing to be net short; that is, 

appearing to lack sufficient generation resources (both owned and purchased) to serve 

their peak load. In reality, franchised public utilities are required by state regulators to 

have sufficient generation resources (owned capacity and firm purchases) to serve their 

projected peak load and an additional “planning reserve margin” on top of that.94 

Although it is unrealistic for franchised public utilities to rely extensively on spot market 

purchases to serve statutory load obligations, that is what is implied in some of the 

indicative screens that have been submitted by franchised public utilities that do not 

include long-term firm purchases in their indicative screens.

77. Moreover, our experience with the horizontal market power analyses submitted 

subsequent to the implementation of Order No. 697 has shown us that in the typical 

situation, the capacity associated with a long-term firm power purchase agreement should 

be attributed to the purchaser, not the seller. This is because long-term firm power 

purchase agreements, including long-term firm energy agreements, provide the purchaser 

with energy that only can be interrupted for limited and specified reasons (e.g., force 

 

94 See, e.g., Staff of the California Public Utilities Commission with the assistance 

of California Energy Commission Staff, 2011 Resource Adequacy Report (Feb. 5, 2013), 

available at http://www.cpuc.ca.gov/PUC/energy/Procurement/RA/.
Docket No. RM14-14-000 52

majeure). A firm energy sale cannot, for example, be interrupted by the seller for 

economic reasons. Thus, a seller must have capacity supporting a firm energy sale and 

this capacity is now effectively serving the purchaser, much like the purchaser’s owned 

generation capacity. 

78. As an example of this, the Commission recently addressed problems associated 

with the misreporting of long-term firm purchases in Vantage Wind.

95

 In Vantage Wind, 

a non-affiliated seller prepared a horizontal market power study for a balancing authority 

area based on the data used by the transmission owner. However, the transmission owner 

failed to properly account for its long-term firm purchases in its indicative screens for its 

home balancing authority area. The transmission owner was entitled to receive the output 

associated with several long-term firm power purchases, but did not report the capacity 

supplying these long-term firm purchases. As a result, the non-affiliated seller appeared 

(incorrectly) to fail the screens because the transmission owner’s capacity effectively was 

underreported. In Vantage Wind, the Commission corrected for this underreporting of 

capacity by directing the load-serving entity purchasers to report all long-term firm 

purchases in Row B of the indicative screens (Long-Term Firm Purchases) if the 

purchase had long-term firm transmission rights associated with those resources.96 This 

direction in the Vantage Wind order resulted in the purchasers having to include the

 

95 Vantage Wind, 139 FERC ¶ 61,063 at P 21.

96 Id.
Docket No. RM14-14-000 53

generation capacity associated with such long-term firm purchases as part of the 

purchasers’ capacity. Otherwise, this generation capacity would have “disappeared” 

from being evaluated under the market-based rate program. We note that in directing this 

outcome, the Commission did not consider the issue of who had operational control of 

the capacity supplying the long-term firm purchases; rather, the Commission assigned the 

capacity to the purchasers under the long-term firm power purchase agreement.

b. Proposal

79. For the reasons stated above, we propose to modify the policy with respect to the 

reporting of long-term firm purchases in the indicative screens. Specifically, we propose 

to require applicants under the market-based rate program to report all of their long-term 

firm purchases97 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. If the long-term firm purchase involves the sale 

of energy, then 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 

 

97 The Commission in Vantage Wind directed the purchasers to report all longterm firm purchases if the purchase had long-term firm transmission rights associated 

with those resources. Id. We assume for purposes of our proposal here that all long-term 

firm purchases necessarily have long-term firm transmission rights associated with them. 

If that is not the case, as noted above, applicants or intervenors are free to raise factspecific circumstances that they believe may support a different attribution of capacity.
Docket No. RM14-14-000 54

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 seller under that power purchase agreement must do 

the same the next time it submits a market-based rate triennial or change of 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).

98

 When making 

these filings, we propose that both the purchaser and the seller must show how they made 

the energy-to-capacity conversion. Although this attribution of capacity is the default

approach that we propose as a general policy, applicants or intervenors are free to raise 

fact-specific circumstances that they believe may support a different attribution of 

capacity. 

 

98 Our understanding is 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.
Docket No. RM14-14-000 55

80. The intent of our proposed reform is to have an entity with market-based rate 

authority 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, we propose that the amount of 

the capacity supplying that purchase must be reported in the purchaser’s screens. We 

also propose to require that all such long-term firm purchases should be reported 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, 

depending on whether the generation resource(s) supplying the sale are located inside or 

outside the seller’s balancing authority area, as explained earlier in this proposed rule. 

81. The proposal to require applicants 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 is supported based on the following 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, sellers 

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 56

82. Second, this proposed change will establish consistent treatment of long-term firm 

sales and long-term firm purchases in the indicative screens. Market-based rate 

applicants typically deduct long-term firm sales without making a determination as to 

whether those sales confer operational control to the purchaser. The Commission, in 

Order No. 697, 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.”99 The Commission clarified that “[s]ellers may deduct 

generation associated with their long-term firm requirements sales, unless the 

Commission disallows such deductions based on extraordinary circumstances.”100

83. It is only on the “buy” side of long-term firm purchases that the Commission has 

considered the issue of control in reporting capacity in the screens.101 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 

power purchase agreement from its capacity for purposes of its screens, but sometimes 

 

99 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 38 (footnotes omitted).

100 Id. n.18.

101 Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at PP 99, 100.
Docket No. RM14-14-000 57

the purchaser does not add the corresponding amount to its capacity for purposes of its 

screens). 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 long-term firm sales with 

respect to the allocation of such capacity. This proposal will make those standards 

consistent, reducing such errors. 

84. 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’s 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.102 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.103 However, applicants typically include all of their owned or 

controlled generation capacity in the indicative screens regardless of whether they 

 

102 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 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. 

103 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 58

actually control the commitment and dispatch of this capacity. Accordingly, we propose

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. 

85. Finally, for those applicants incorrectly reporting long-term firm power purchases 

in the wrong row of the indicative screens, 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. 

As the Commission noted in Vantage Wind,

104 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. 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 

 

104 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 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 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 Sound Energy, Inc., 135 FERC ¶ 61,254 (2011)]. 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 59

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, 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. 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. This proposal is intended to 

help clarify how to classify imports of firm power and remotely-owned capacity. These 

proposed changes to the pivotal supplier screen format are also being proposed for the

market-share screen.

86. We seek comment on this proposal.

B. Vertical Market Power – Land Acquisition Reporting 

1. Current Policy

87. All market-based rate sellers are currently required, pursuant to § 35.42(d) of the 

Commission’s regulations and Order Nos. 697-C and 697-D, to file notices of change in 
Docket No. RM14-14-000 60

status on a quarterly basis when they acquire sites for new generation capacity 

development.

105 To date, not a single protest has been filed in response to these copious 

filings and the Commission has not uncovered any issues indicating that a particular 

seller has erected a barrier to entry as a result of its land acquisition. On a number of 

occasions over the years, market-based rate sellers have expressed frustration with this 

reporting requirement and have described it as burdensome. 

88. In Order No. 697, the Commission stated it would consider a seller’s ability to 

erect other barriers to entry as part of the vertical market power analysis. Thus, the 

regulations require that a seller provide a description of its ownership or control of, or 

affiliation with an entity that owns or controls, intrastate natural gas transportation, 

intrastate natural gas storage or distribution facilities, sites for generation capacity

development, and physical coal supply sources and ownership or control over who may 

access transportation of coal supplies.106 The Commission noted that, to date, it had not 

found such ownership or control to be a potential barrier to entry warranting further 

analysis, but that it did not have sufficient evidence to remove these inputs from the 

analysis entirely. Thus, it rebuttably presumed that ownership or control of or affiliation 

with an entity that owns or controls such facilities does not allow a seller to raise entry 

 

105 Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 at PP 18-19; Order No. 697-D 

FERC Stats. & Regs. ¶ 31,305 at PP 21-23.

106 18 CFR 35.37(e).
Docket No. RM14-14-000 61

barriers, but would allow intervenors to demonstrate otherwise.107 In Order No. 697-C, 

the Commission noted that “[o]ne of the purposes of the change of status reporting 

requirement is to provide interested parties the opportunity to intervene and comment if 

they believe the seller’s acquisition of sites for new generation capacity development 

creates a barrier to entry.”108

2. Proposal

89. We propose to relieve market-based rate sellers of their obligation to file quarterly 

land acquisition reports and of the obligation to provide information on sites for 

generation capacity development in market-based rate applications and triennial updated 

market power analyses because the burden of such reporting outweighs the benefits.109

90. In the more than six years since issuance of Order No. 697, intervenors have not 

challenged whether sites for new generation capacity development created a barrier to 

entry. For this reason, we propose to eliminate the requirement to provide such 

information. We note that, if there is a concern that a particular seller’s sites for 

 

107 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 446.

108 Order No. 697-C, FERC Stats. & Regs. ¶ 31,291 at P 17.

109 For an example of the burden, the Commission received, in the most recent 

seven quarters, 90 filings from 1,380 filers. This is a reporting burden on the 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. All 1,380 filers had to be 

listed in the notices and in the orders accepting the filings. Staff has written and issued 

seven orders accepting these filings, one order for each of the last seven quarters. 
Docket No. RM14-14-000 62

generation capacity development may be creating a barrier to entry, the Commission can 

request additional information from the seller at any time.110 

91. Thus, we propose to revise the regulations at 18 CFR 35.42 to remove paragraph 

(d). This proposed revision removes 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, we propose 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). We also propose to revise the 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. 

Therefore, under this proposal, § 35.42(d)-(e) and § 35.37(e)(2) would be removed 

entirely. In addition, we propose to revise 18 CFR 35.42 at paragraph (b) to remove the 

reference to the reporting of acquisition of control of a site or sites for new generation 

capacity development. Specifically, under this proposal, § 35.42(b) would read as 

follows: 

Any change in status subject to paragraph (a) of this section, other 

than a change in status submitted to report the acquisition of control 

of a site or sites for new generation capacity development, must be 

filed no later than 30 days after the change in status occurs. Power 

sales contracts with future delivery are reportable 30 days after the 

 

110 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 63

physical delivery has begun. Failure to timely file a change in status 

report constitutes a tariff violation.

92. We seek comment on these proposals.

C. Notices of Change in Status

93. Section 35.42(a) of the Commission’s regulations requires sellers to report any 

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

relied upon in granting market-based rate authority.111 A change in status filing is 

required when, among other things, either of two conditions are met:

(1) ownership or control of generation capacity results in net increases of 100 MW 

or more;[

112] or

(2) affiliation with any entity not disclosed in the application for market-based rate 

authority that (a) owns or controls generation facilities or inputs to electric power 

production, (b) owns, operates or controls transmission facilities, or (c) has a 

franchised service area.[

113] 

1. Geographic Focus

a. Current Policy

94. 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 

 

111 18 CFR 35.42(a).

112 18 CFR 35.42(a)(1).

113 18 CFR 35.42(a)(2).
Docket No. RM14-14-000 64

of the horizontal market power analysis on which the Commission relied in granting the 

seller market-based rate authority.”114 

95. Order No. 697-A also provided an example of when a seller should not file a 

notice of change in status: “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 a 50 MW increase in a different geographic market that is in the same region as 

defined by Appendix D of Order No. 697, 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.”115 

b. Proposal

96. We propose to clarify that the 100 MW reporting threshold in § 35.42(a)(1) is not 

limited only to markets previously studied. That is, 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 firsttier/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 

 

114 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 512.

115 Id. We note that the original text in Order No. 697-A stated “the increase in 

generation is less than 50 MW in each generation market.” However, it should have 

stated “the increase in generation is less than 100 MW in each generation market.” 
Docket No. RM14-14-000 65

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. We 

clarify that a net increase measures the difference between increases and decreases in 

affiliated generation. We further clarify that the example cited above from Order 

No. 697-A described a situation where the geographic market on which the Commission 

relied was not first-tier to the geographic market in which the seller acquired an 

additional 50 MW. Thus, we propose 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. We further propose to require that the 

100 MW threshold requirement for change in status filings be calculated based on a 

generator’s nameplate 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.

97. Therefore, we propose to revise the regulatory text in § 35.42(a)(1) of the 

Commission’s regulations to provide greater clarity and direction on this topic as follows:

Ownership or control of generation capacity 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 relevant 

geographic market (including generation in the relevant geographic market and 

generation in any markets that are first tier to the relevant geographic market), or 
Docket No. RM14-14-000 66

of inputs to electric power production, or ownership, operation or control of 

transmission facilities, or

98. We seek comment on these proposals.

2. Long-Term Contracts

a. Current Policy

99. As noted above, sellers are currently required to report ownership or control of 

generation capacity that results in net increases of 100 MW or more but are not required 

to report contracts that do not convey ownership or control of generation capacity.116

b. Proposal

100. As discussed above, we propose to require sellers to report all long-term firm 

purchases of capacity and/or energy in their indicative screens, regardless of whether the 

seller has acquired control over the generation capacity supplying the power. The change 

in status reporting requirement in § 35.42 seeks to provide a timely report of “any change 

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

upon in granting market-based rate authority.”

117

 We propose above to require reporting 

of long-term firm purchases in the indicative screens; such purchases will be relied upon 

in granting market-based rate authority. Therefore, in addition to the revisions proposed 

above, we propose to include such contracts when determining the 100 MW threshold 

 

116 See 18 CFR 35.42(a)(1).

117 18 CFR 35.42(a).
Docket No. RM14-14-000 67

and propose to revise the beginning of § 35.42(a)(1) of the Commission’s regulations as 

follows:

Ownership or control of generation capacity or long-term firm purchases of 

capacity and/or energy that results in net increases...[

118]

101. We seek comment on this proposal.

3. New Affiliation and Behind-the-Meter Generation 

a. Current Policy

102. Market-based rate sellers are required to make a change in status filing when they 

become affiliated with entities that: (1) own or control generation; (2) own or control 

inputs to electric power production (e.g., intrastate natural gas transportation, storage, or 

distribution facilities); (3) own, operate or control transmission facilities; or (4) have a 

franchised service territory.

119

 Currently, the 100 MW threshold for reporting increases 

in generation contained in § 35.42(a)(1) of the Commission’s regulations does not apply 

to the requirement to report a new affiliation found in § 35.42(a)(2) of the Commission’s 

 

118 When the changes to § 35.42(a)(1) as proposed here are combined with the 

changes to § 35.42(a)(1) proposed above, the revised § 35.42(a)(1) would read as 

follows:

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 relevant geographic market (including 

generation in the relevant geographic market(s) and generation in any markets that 

are first tier to the relevant geographic market(s)), or of inputs to electric power 

production, or ownership, operation or control of transmission facilities, or

119 18 CFR 35.42(a)(2).
Docket No. RM14-14-000 68

regulations because the existing language in § 35.42(a)(2) does not reference the 

100 MW threshold. As a result, § 35.42(a)(2) requires a change in status filing for any

new affiliation, regardless of the amount of generation owned or controlled by the new 

affiliate. 

103. In addition, the regulatory text states that a change in status filing is required for 

any new affiliate that owns or controls generation facilities, without regard to the size, 

type or characteristics of those facilities.120 The Commission’s experience is that some 

sellers are unsure if they should report new affiliates that own certain facilities such as 

qualifying facilities that are exempt from FPA section 205121 and behind-the-meter 

facilities. 

104. Finally, the Commission’s experience is that some sellers report the new 

acquisition or new affiliation in the text of their change in status filings but do not include 

the generation in the asset appendix, especially when it is behind-the-meter generation.

b. Proposal

105. We propose to revise the 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 until its new affiliations result 

 

120 See id.

121 Sales of energy or capacity made by qualifying facilities 20 MW or smaller are 

exempt from section 205. Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 525; 

18 CFR 292.601(c)(1).
Docket No. RM14-14-000 69

in a cumulative net increase of 100 MW or more of nameplate capacity in any relevant 

geographic market (including generation in both the relevant geographic market itself and 

any first-tier/interconnected market). As noted above, the Commission adopted a 

100 MW threshold for reporting new generation, finding that a minimum reporting 

threshold 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.122 Similarly, we believe that 

applying the 100 MW threshold to new affiliations would ease the reporting burden on 

sellers without diminishing the Commission’s ability to identify possible market power. 

Therefore, we propose to revise § 35.42(a)(2) of the Commission’s regulations to read as 

follows:

Affiliation with any entity not disclosed in the application for market-based rate 

authority that:

(i) oOwns 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 nameplate capacity in any relevant geographic market (including 

generation in the relevant geographic market(s) and generation in any markets that 

are first tier to the relevant geographic market(s));

(ii) Owns or controls inputs to electric power production;,

(iii) affiliation with any entity not disclosed in the application for market-based 

rate authority that oOwns, operates or controls transmission facilities;, or 

(iv) affiliation with any entity that hHas a franchised service area.

 

122 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 70

106. We further clarify 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 appendix. We propose to amend the regulation to 

clarify that sellers must include all new affiliates and any assets owned or controlled by 

the new affiliates in the asset appendix. We propose to revise § 35.42(c) of the 

Commission’s regulations as follows:

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.

107. We further clarify that “all assets” include behind-the-meter generation and 

qualifying facilities.123 However, we propose to allow sellers to aggregate their behindthe-meter generation by balancing authority area or market into one line on the list of 

generation assets. Similarly, we propose 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. 

108. We also clarify that sellers should include these assets in their indicative screens, 

as well as in their asset appendix. Sellers should also include this generation when 

 

123 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 study should 

be listed in the asset appendix. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 895.
Docket No. RM14-14-000 71

calculating the 100 MW change in status threshold and the 500 MW Category 1 

threshold.

109. We seek comment on these proposals.

D. Asset Appendix

1. Current Policy

110. Order No. 697 requires that market-based rate sellers include with each new 

application, market power analysis, and relevant change in status notification an asset 

appendix that lists all affiliates that have market-based rate authority and identifies any 

assets owned or controlled by the seller and any such affiliate.124 The asset appendix 

includes two lists of assets. One list contains market-based rate affiliates and generation 

assets and the other list contains electric transmission and intrastate natural gas assets. 

The appendix must list all generation assets owned or controlled by the corporate family, 

and each asset’s balancing authority area (clearly identifying which affiliate owns or 

controls which asset), geographic region, in-service date, and nameplate and/or seasonal 

ratings.125 The transmission list of assets must reflect all electric transmission and natural 

gas intrastate pipelines and/or gas storage facilities owned or controlled by the corporate 

family and the location of such facilities.126 The Commission requires the appendix of 

 

124 Id. P 894.

125 Id. P 895.

126 Id.
Docket No. RM14-14-000 72

assets to be included in the form provided in Appendix B to Subpart H of Part 35 of the 

Commission’s regulations, and provides an example of the required appendix on its Web 

site.127

2. Proposal

111. As detailed below, we propose clarifications and revisions to the required 

appendix that contains the lists of assets. 

a. Changes to the Existing Columns 

112. We propose to make three changes to the existing columns in the asset appendix. 

We propose to change the column headings on both lists of assets 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 

is to change the column headings on both lists of assets from “Geographic Region (per 

Appendix D)” to “Geographic Region” because there have been changes to some sellers’

regions since the Commission originally published the region map in Appendix D of 

Order No. 697. Finally, we propose to change the heading for the “Nameplate and/or 

Seasonal Rating” column 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 of the asset appendix should use either “nameplate,” “seasonal,” or 

five-year average rating to reflect the rating used throughout the filing for a particular 

 

127 The sample asset appendix can be found on the Commission’s Web site at 

http://www.ferc.gov/industries/electric/gen-info/mbr/appendix.pdf.
Docket No. RM14-14-000 73

generation technology. These proposed changes will ensure consistency across filings

and allow the industry and Commission staff to better utilize the information contained in 

the lists of assets.

113. Thus, we propose 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.128 

114. We seek comment on these proposed changes.

b. Clarifications Regarding the Existing Columns

115. The Commission’s post-Order No. 697 experience has been that, with respect to 

the currently labeled “Nameplate and/or Seasonal Rating” column in the list of generation 

assets, some sellers report only the portion of the capacity that they own,129 whereas other 

sellers report the entire capacity of the facility. Additionally, some sellers include in their 

asset lists generation facilities in which they have claimed a familial relationship through 

only passive, non-controlling interests.

116. We propose to clarify that, for the list of assets: (1) a seller must enter the entire 

amount of a generator’s capacity (in MWs) in the “Capacity Rating (MW): Nameplate,

 

128 See Appendix B herein for an example of the proposed revised appendix.

129 We note that the Commission 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, 138 FERC ¶ 61,107, at P 28 (2012). Instead, 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.
Docket No. RM14-14-000 74

Seasonal, or Five-Year Average” column 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: transmission, intrastate natural gas storage, intrastate natural gas transportation, 

or intrastate natural gas distribution; (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.

130

 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,131 and thus account for only 

its portion of that 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. We note that generating units within a single plant may be aggregated in a 

single row if the information in the other columns is the same for all units, but separate 

plants cannot be aggregated in a single row, except for behind-the-meter generation, and 

qualifying facilities less than 20 MW, as proposed above. We further clarify 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 

 

130 We note that sellers must demonstrate why such ownership interests should be 

deemed passive. See AES Creative Resources, L.P., 129 FERC ¶ 61,239 (2009). 

131 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 187. 
Docket No. RM14-14-000 75

registered in the Commission’s company registration database,

132 we propose to clarify 

that the name in the asset appendix for that company must appear exactly the same as in 

the registration database. 

117. With respect to the “Date Control Transferred” column in both the generation and 

transmission asset lists, we clarify that the “Date Control Transferred” column should 

identify the date on which a contract 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).

118. With respect to the “Size” column in the list of transmission assets, we propose 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). We note that companies can aggregate 

their transmission assets by voltage. For instance, a utility 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, 

 

132 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 Order Updating Electric Quarterly Report Data Dictionary, 146 FERC ¶ 61,169 

(2014)).
Docket No. RM14-14-000 76

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.”

119. We seek comment on these proposals.

c. Changes Regarding OATT Waiver and Citations in 

Transmission Assets

120. 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 

appendix,

133 and we believe that this should be reiterated and clarified going forward. 

Therefore, we propose to require any seller that has been granted waiver of the 

requirement to file an OATT for its facilities134 to report in its list of transmission assets 

the citation to the Commission order granting the OATT waiver for those facilities. We 

propose 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 list of 

transmission assets for the citation to the Commission order accepting the OATT or 

granting waiver of the OATT requirement. This will make the list of transmission assets 

consistent with the list of generation assets, which already contains a column for the 

 

133 “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.

134 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 408.
Docket No. RM14-14-000 77

docket number in which market-based rate authority was granted, and will provide a 

more complete list of transmission assets to the Commission and the public. Providing 

the citation to the Commission order accepting the OATT or granting waiver of the 

OATT requirement in the list of transmission assets will facilitate the Commission’s and

market participants’ verification that sellers were granted the appropriate authorizations.

121. We seek comment on these proposed changes.

d. Electronic Format

122. Currently, virtually all of the asset lists 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 lists of assets. Staff therefore frequently transfers the information 

included in the lists of assets into spreadsheets for sorting, comparison purposes, and 

internal calculations, and has found numerous submission errors from sellers. If the 

Commission provided a sample electronic spreadsheet and required sellers to submit the

lists of assets 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.

123. Therefore, we propose 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. We propose to post on the Commission’s 

Web site sample lists of assets in formatted electronic spreadsheets and to require sellers 
Docket No. RM14-14-000 78

to submit all required appendices in the form and format of the sample electronic 

spreadsheets.

135

 

124. We further propose to clarify that the lists of assets 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 

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. We discourage any 

such footnotes and direct that any such representations be made in the filing transmittal 

letter.

125. An example of the electronic spreadsheet for the appendix with the new columns 

and column headings is included as Appendix B herein.

e. Database 

126. As noted above, we propose to require market-based rate sellers to submit their 

lists of assets in an electronic spreadsheet that can be searched, sorted, and otherwise 

accessed using electronic tools. In addition, we seek comment whether in the future it 

 

135 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 Web 

site. Specifically, it must have the same exact columns and descriptive text as the sample 

spreadsheet. The file must be submitted in one of the spreadsheet file formats accepted 

by the Commission for electronic filing. See FERC, Acceptable File Formats (January 

2012), available at http://www.ferc.gov/docs-filing/elibrary/accept-file-formats.asp.
Docket No. RM14-14-000 79

would be beneficial to develop a comprehensive searchable public database of the 

information contained in the asset appendices, which would eventually replace the

pre-formatted spreadsheet. Such an approach would allow market-based rate sellers to 

update their asset appendices when circumstances change. We seek input 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. We 

further seek 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 IDs 

exist. We also seek input on the difficulty of reporting and the usefulness of including in 

such a database the percentage each affiliate owns of each of its assets.

127. We seek comment on these proposals.

E. Category 1 and Category 2 Sellers

1. Current Policy

128. In Order No. 697, the Commission created a category of market-based rate sellers 

(Category 1 sellers) that are exempt from the requirement to automatically submit 

updated market power analyses. 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;136 that do not own, operate or control transmission facilities other 

 

136 In Order No. 697, the Commission adopted a regional schedule for the 

submission of updated market power analyses based on the balancing authority area in 

 (continued...)
Docket No. RM14-14-000 80

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 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 issues.137 Category 2 sellers (those market-based 

rate sellers that do not qualify as Category 1 sellers) are required to file regularly 

scheduled updated market power analyses.138

129. In practice, the criteria for Category 1 seller status have been applied differently in 

the case of power marketers (i.e., a seller that does not own generation or transmission)

and power producers (i.e., a seller with generation assets).139 The seller category status 

for a power marketer is determined by considering all affiliated generation and 

 

which the seller owns or controls generation. The Commission established the following 

six geographic regions: Northeast, Southeast, Central, Southwest Power Pool, 

Southwest, and Northwest. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at 

Appendix D. We provide an updated region map as Appendix D of this NOPR.

137 See id. PP 848-849 n.1000; see also 18 CFR 35.36(a)(2), 35.37(a)(1).

138 18 CFR 35.36(a)(3), 35.37(a)(1).

139 The distinction between the category status of power marketers and power 

producers was previously articulated in the March 2010 market-based rate technical 

conference. FERC, Technical Conference on Preparation of Market-Based Rate Filings 

Quarterly Reports by Public Utilities, Docket No. AD10-4-000 (2010), available at

https://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=5089&CalType=%20&Cale

ndarID=116&Date=03/03/2010&View=Listview).
Docket No. RM14-14-000 81

transmission, while power producers owning generation or transmission assets only have 

to consider affiliated generation if it is located in the same region as the power producer’s 

generation assets.

2. Proposal

130. We propose to clarify the distinction in determining the seller category status of 

power marketers and power producers.140 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 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. 

However, 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.

 

140 The Commission regulations define Category 1 sellers as “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, FERC Stats. & Regs. ¶ 31,036); 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 seller’s generation assets; and that do not raise other vertical market power issues.” 

18 CFR 35.36(a)(2).
Docket No. RM14-14-000 82

131. Thus, we propose 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 power issues. In addition, for 

any region where the power marketer’s affiliates are designated as Category 2 sellers, it is 

Commission practice that the power marketer is also a Category 2 seller. We note that 

the above is consistent with the way in which the Commission has viewed power 

marketers since the issuance of Order No. 697. 

132. We also propose 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.

141

 

141 We note 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 

 (continued...)
Docket No. RM14-14-000 83

133. Therefore, we propose to revise the regulations to clarify that 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. The proposed change of the text 

of 18 CFR 35.36(a)(2) is: 

A Category 1 Seller means a Seller that:

(i) Is either a wholesale power marketers that controls or is affiliated with 

500 MW or less of generation in aggregate per region or a wholesale power 

producers that owns, or controls or is affiliated with 500 MW or less of generation 

in aggregate in the same region as its generation assets; 

(ii) that do Does not own, operate or control transmission facilities other than 

limited equipment necessary to connect individual generating facilities to the 

transmission grid (or has have been granted waiver of the requirements of Order 

No. 888, FERC Stats. & Regs. ¶ 31,036); 

(iii) that are Is not affiliated with anyone that owns, operates or controls 

transmission facilities in the same region as the Seller's generation assets; 

(iv) that are Is not affiliated with a franchised public utility in the same region as 

the Sseller's generation assets; and 

(v) that do Does not raise other vertical market power issues.

134. We seek comment on this proposal.

F. Corporate Families

1. Corporate Organizational Charts

a. Current Policy

135. The Commission currently requires new and existing market-based rate sellers to 

provide written descriptions of their affiliates and corporate structure or upstream 

ownership for initial applications for market-based rate authority, updated market power 

 

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 84

analyses and notices of change in status as a result of new affiliations. In Order No. 697-

A, the Commission stated:

A seller seeking market-based rate authority must provide information 

regarding its affiliates and its corporate structure or upstream ownership. 

To the extent that a seller’s owners are themselves owned by others, the 

seller seeking to obtain or retain market-based rate authority must identify 

those upstream owners. Sellers must trace upstream ownership until all 

upstream owners are identified. Sellers must also identify all affiliates. 

Finally, an entity seeking market-based rate authority must describe the 

business activities of its owners, stating whether they are in any way 

involved in the energy industry.[

142]

b. Proposal

136. We propose 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.

137. The Commission has seen increasingly complex organizational structures as 

private equity funds and other financial institutions take ownership positions in 

generation and utilities. The Commission believes that requiring the filing of an 

organizational chart for initial applications for market-based rate authority, updated 

market power analyses and notices of change in status reporting new affiliations would

make reviewing market-based rate filings more efficient, increase transparency, and 

synchronize information about corporate structure that the Commission receives from 

 

142 Id. P 181 n.258.
Docket No. RM14-14-000 85

sellers with market-based rate authority with similar information that the Commission 

receives under section 203 of the FPA.

143 We propose to require from market-based rate 

sellers an organizational chart similar to that which the Commission requires from section 

203 applicants. Specifically, § 33.2(c)(3) of the Commission’s regulations144 provides 

that section 203 applicants must include: a description of the applicant, including, among 

other things, “[o]rganizational charts depicting the applicant’s current and proposed posttransaction corporate structures (including any pending authorized but not implemented 

changes) indicating all parent companies, energy subsidiaries and energy affiliates unless 

the applicant demonstrates that the proposed transaction does not affect the corporate 

structure of any party to the transaction.” We propose that market-based rate sellers be 

required to provide written descriptions of their affiliates and corporate structure or 

upstream ownership and 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. We

believe that the increased burden on market-based rate sellers is minimal as most sellers 

have this organizational chart available.

138. Thus, we propose to revise the regulatory text in § 35.37(a)(2) of the 

Commission’s regulations as follows:

 

143 16 U.S.C. 824b.

144 See 18 CFR 33.2(c)(3).
Docket No. RM14-14-000 86

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, written descriptions of their affiliates and corporate 

structure or upstream ownership, and an organizational chart. The organizational 

chart must depict the Seller’s current corporate structure indicating all upstream 

owners, energy subsidiaries and energy affiliates.

139. We also propose 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, we 

propose to revise the regulatory text in § 35.42(c) of the Commission’s regulations as 

follows:

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 assets in the form provided in 

Appendix B of this subpart, written descriptions of their affiliates and corporate 

structure or upstream ownership, and an organizational chart. The organizational 

chart must depict the Seller’s prior and new corporate structures indicating all 

upstream owners, energy subsidiaries and energy affiliates unless the Seller 

demonstrates that the change in status does not affect the corporate structure and 

the Seller’s affiliations.[

145]

 

145 When the changes to § 35.42(c) as proposed here are combined with the 

changes to § 35.42(c) proposed above, the revised § 35.42(c) would read as follows:

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, written descriptions of their affiliates and corporate 

structure or upstream ownership, and an organizational chart. The organizational 

chart must depict the Seller’s prior and new corporate structures indicating all 

upstream owners, energy subsidiaries and energy affiliates unless the Seller 

demonstrates that the change in status does not affect the corporate structure and 

the Seller’s affiliations. 
Docket No. RM14-14-000 87

140. We seek comment on these proposals.

2. Single Corporate Tariff

a. Current Policy

141. Joint tariffs may be used when a corporate family has more than one affiliated 

seller with market-based rate authority.146 Joint tariffs allow corporate families to more 

clearly organize their tariff records and simplify their tariff filings. The Commission 

explained in Order No. 714 that joint filers are permitted to designate one market-based 

rate seller (the designated filer) to file a single tariff (joint master corporate tariff) for 

inclusion in the Commission’s eTariff database that reflects the joint tariff for itself and 

all affiliated sellers.147 The Commission further explained that all affiliated sellers (i.e., 

the non-designated joint filers) would include in their respective tariff filings a tariff 

section consisting of a single page or section that would provide the appropriate name of 

the tariff and the identity of the designated filer for the joint tariff. In this way, nondesignated filers incorporate by reference the joint master corporate tariff submitted by 

the designated filer, and staff and the general public are able to find quickly the 

appropriate joint master corporate market-based rate tariff in the Commission’s eTariff 

database.

 

146 Electronic Tariff Filings, Order No. 714, FERC Stats. & Regs. ¶ 31,276, at 

P 60 (2008).

147 See id. P 63. 
Docket No. RM14-14-000 88

142. Several corporate families have successfully submitted a joint master corporate 

market-based rate tariff; however, others have experienced technical and non-technical 

difficulties when filing their tariff records into the Commission’s electronic tariff 

database. Other corporate families continue to maintain their market-based rate tariffs 

separately. Having a joint master corporate market-based rate tariff eases the regulatory 

burden on corporate families because only the designated filer is required to submit tariff 

revisions, such as when mitigation is changed for the entire corporate family or when 

Commission-approved or required language in the tariff needs updating, and results in a 

more efficient use of seller and agency resources. 

b. Proposal

143. We clarify on the Commission’s Web site 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. That information 

can be found on the Commission’s Web site at 

http://www.ferc.gov/industries/electric/gen-info/mbr/tariff/joint.asp. 

G. Clarification of Commission Language in Performing SIL Studies

1. Current Policy

a. OASIS Practices

144. The Commission adopted the requirement that the SIL study be used in both the 

indicative screens and the DPT analysis as the basis for establishing the amount of power 
Docket No. RM14-14-000 89

that can be imported into the relevant geographic market.148 The Commission also stated 

that the SIL study shown in Appendix E of the April 14, 2004 Order is the only study that 

meets this requirement.149 

145. The Commission’s OASIS requirements are intended to ensure that potential 

transmission customers receive access to information that will enable them to obtain 

transmission service on a non-discriminatory basis from any transmission provider. The 

transmission provider’s OASIS provides, among other things, information by electronic 

means about ATC for point-to-point service and provides a process for requesting 

transmission service.150 

b. SIL Studies and OASIS Practices

146. In Order No. 697, the Commission found that SIL studies performed by sellers 

“should not deviate from” and “must reasonably reflect” the seller’s OASIS operating 

practices and “techniques used must have been historically available to customers.”151 

Order No. 697 also stated that

 

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

149 Id. (citing April 14, 2004 Order, 107 FERC ¶ 61,018 at Appendix E). The 

April 14, 2004 Order predates Order No. 697. However, Order No. 697 largely adopts 

the requirements of the April 14, 2004 Order. Id. PP 19, 354-362.

150 18 CFR 37.2, 37.6(b). 

151 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354 (citing Market-Based 

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

Utilities, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,602, at PP 77, 78 

(2006)).
Docket No. RM14-14-000 90

[b]y 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.

152

147. Furthermore, the April 14, 2004 Order requires that the seller 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 in assessing available 

transmission for non-affiliate resources.”153

Similarly, in Pinnacle West,

154 148. the Commission found that “simultaneous 

transmission import capability used in the market screens should account for how 

transmission is actually provided by the applicant,” explaining that “simultaneous 

transmission import capability calculations should be based on actual historic 

conditions.”155 

 

152 Id. n.361.

153 April 14 Order, 107 FERC ¶ 61,018 at Appendix E.

154 Pinnacle West Capital Corp., 109 FERC ¶ 61,295 (2004), clarified, 110 FERC 

¶ 61,127 (2005) (Pinnacle West). Pinnacle West predates Order No. 697. However, 

Order No. 697 largely affirms statements made in Pinnacle West. Order No. 697, FERC 

Stats. & Regs. ¶ 31,252 at PP 354-362.

155 Pinnacle West, 110 FERC ¶ 61,127 at P 8.
Docket No. RM14-14-000 91

149. Additionally, in Carolina Power & Light, the Commission clarified footnote 361 

of Order No. 697, stating that “in performing SIL studies, applicants should follow 

OASIS practices historically used by the study area and aggregated first-tier balancing 

authority areas.”156 

150. In Puget, the Commission largely reiterated and consolidated direction previously 

provided in Order No. 697, the April 14, 2004 Order, Pinnacle West, and Carolina Power 

& Light. The Commission 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 study results.

157

 In addition, the 

Commission 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 nonaffiliated load in net area interchange.158

 Finally, the Commission required that 

applicants document all instances where the SIL study differs from historical practices.159

 

156 Carolina Power & Light Co., 128 FERC ¶ 61,039, at P 7 (Carolina Power 

& Light), clarified, 129 FERC ¶ 61,152 (2009).

157 Puget, 135 FERC ¶ 61,254 at Appendix B, Reporting Requirements for 

Submittals 8, 9.

158 Id. at Reporting Requirements for Submittal 10. 

159 Id. at Reporting Requirements for Submittal 11.
Docket No. RM14-14-000 92

151. The April 14, 2004 Order further requires that power flow benchmark cases 

should represent “operational practices historically used” and “reasonably simulate the 

historical conditions that were present.”160 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 [Transmission Provider] TP 

during the season peaks.[

161]

152. In addition, Order No. 697 requires that power flow cases “represent the 

transmission provider’s tariff provisions and firm/network reservations held by 

seller/affiliate resources during the most recent seasonal peaks.”162 

153. In Puget, the Commission stated that “[l]ong-term firm transmission reservations 

for applicant/affiliate generation resources that serve study area load reduce the amount 

of study area transmission capability available to potential competitors” and that 

“[f]ailing to properly account for such reservations is inconsistent with the Commission’s 

methodology for calculating SIL values.”163

 

160 April 14, 2004 Order, 107 FERC ¶ 61,018 at Appendix E.

161 Id.

162 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354.

163 Puget, 135 FERC ¶ 61,254 at P 15.
Docket No. RM14-14-000 93

154. In addition, the Commission stated that the transmission capability associated with 

study area long-term firm import transmission reservations also must be subtracted from 

the study area’s native load to accurately represent the amount of study area native load 

available to be served by first-tier area generation.164 This direction is reflected in Row 8 

of Submittal 1 found in Appendix B of Puget.

165

c. Simultaneous TTC

155. Order No. 697 allows the use of simultaneous TTC values in performing SIL 

studies. The Commission stated that this was permissible “provided that these TTCs are 

the values that are used in operating the transmission system and posting availability on 

OASIS.” The Commission required sellers to provide evidence that simultaneous TTC 

values account for simultaneity, internal and first-tier external transmission limitations, 

and transmission reliability margins; and are used in operating the transmission system 

and posting availability on OASIS.166

156. In Order No. 697-A, the Commission clarified 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.”167

 

164 Id. P 16.

165 Id. at Appendix B.

166 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 364.

167 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 142.
Docket No. RM14-14-000 94

2. Proposal

157. We propose to provide clarification regarding several issues that have arisen 

regarding the proper way to perform SIL studies. In particular, the we propose 

clarification on issues relating to what is included in “OASIS practices,” how to deal with 

conflicts between OASIS practices and the Commission directions provided in 

Appendix B of Puget, and the correct load value to use in the SIL study.

158. 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., long-term firm transmission 

reservations). Therefore, the methodology a transmission provider uses to calculate 

simultaneous TTC values168 must be consistent with the methodology used for 

calculating and posting ATC and for evaluation of firm transmission service requests, 

consistent with Commission policy and precedent. Import capability available to a 

transmission provider during real-time operations should not be included in the 

transmission provider’s SIL value if such import capability is not available to nonaffiliated uncommitted generation resources requesting long-term firm transmission 

service. The following clarifications are therefore proposed.

 

168 See Row 4 of proposed Submittal 1 (Total Simultaneous Transfer Capability).
Docket No. RM14-14-000 95

a. OASIS Practices

159. As discussed above, the methodology a transmission provider uses to calculate 

SIL values must be consistent with the methodology it uses for calculating and posting 

ATC169 and for evaluating transmission service requests. We propose the following 

clarifications:

160. We propose to clarify that the term “OASIS practices” refers specifically to the 

seasonal benchmark power flow case modeling assumptions, study solution criteria,170

and operating practices historically used by the first-tier and study area transmission 

providers171 to calculate and post ATC and to evaluate requests for firm transmission 

service.172

 

169 Section 15.2 (Determination of Available Transfer Capability) of the pro forma 

OATT states “[i]n the event sufficient transfer capability may not exist to accommodate a 

service request, the Transmission Provider will respond by performing a System Impact 

Study.” See Preventing Undue Discrimination and Preference in Transmission Service, 

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

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

(2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on 

clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

170 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.

171 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. See Order No. 697, FERC Stats. & Regs ¶ 31,252 at P 354 n.361.

172 While the OASIS practices associated with non-firm transmission service may 

result in a higher SIL value, the interruptible nature of such service makes it 

 (continued...)
Docket No. RM14-14-000 96

161. Second, we propose 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 transmission 

service requests, the transmission provider should not be allowed to use the operating 

guide when calculating SIL values.173 

b. SIL Studies and OASIS Practices

162. Where there is a conflict between the transmission provider’s tariff or OASIS 

practices and the directions specified in the Puget order for performing SIL studies, we 

propose to clarify that sellers should follow OASIS practices except as noted below. 

Sellers are reminded that, in instances where actual OASIS practices differ from the SIL 

direction provided in Puget, sellers should both use actual OASIS practices and provide 

 

inappropriate as a measure of uncommitted generation capacity in the first-tier available 

to compete in the study area.

173 By “operating guide” we are generally referring to the 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.
Docket No. RM14-14-000 97

documentation specifically identifying such practices.174 We propose to clarify that to the 

extent that a seller’s SIL study departs from actual OASIS practices,175 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. We invite comments identifying 

potential areas where actual OASIS practices may be incompatible with the performance 

of SIL studies.

163. Further, we remind sellers that the calculated SIL value should account for any 

limits defined in the tariff, such as stability or voltage.176 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.177 

 

174 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 356.

175 See Puget, 135 FERC ¶ 61,254 at Appendix B.

176 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 346.

177 See 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.”).
Docket No. RM14-14-000 98

164. We also reiterate that sellers may use load scaling to perform a SIL study if they 

use load scaling 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.”178

165. Further, we propose to clarify that when properly accounting for long-term firm 

transmission reservations for generation resources that serve study area load, sellers must 

reduce the simultaneous TTC value179 by subtracting all long-term firm import 

transmission reservations.

180

 The Commission 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.181 The proposed 

revised Appendix A Standard Screen Format accounts for all long-term firm import 

transmission reservations into the study area.

182

 Therefore, we propose to direct 

 

178 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 145. 

179 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 long-term firm reservations from Submittal 1, Table 1, Row 5 of Puget. Puget, 

135 FERC ¶ 61,254 at Appendix B.

180 See Revised Appendix E, Submittal 1, Row 5.

181 Puget, 135 FERC ¶ 61,254 at P 15.

182

 See Revised Appendix 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.
Docket No. RM14-14-000 99

applicants to subtract all long-term firm import transmission reservations, including 

reservations held by non-affiliated sellers, from the simultaneous TTC value. We 

propose revisions to Submittal 2 to account for these non-affiliate long-term firm 

reservations. Accounting for all long-term firm reservations ensures that the 

determination of the SIL study 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. Sellers should refer to Submittal 1 for further information. 

166. Finally, we propose 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 seller should reduce the simultaneous 

TTC value by subtracting the value of all wheel-through transactions. These transactions 

should be accounted for as long-term firm import transmission reservations, and reported 

in Submittal 2. We propose revisions to Submittal 2 to account for wheel-through 

transactions. While such generation is not used to serve study area load, it still reduces 

the amount of transmission capability available to first-tier generators competing to serve 

study area load. 

167. We propose to clarify that, where a first-tier market or balancing authority area is 

directly interconnected to the study area only by controllable tie lines183 and is not 

 

183 Controllable tie lines include DC transmission facilities and AC transmission 

facilities with the ability to control the magnitude and direction of power flows through 

 (continued...)
Docket No. RM14-14-000 100

interconnected to any other first-tier market or balancing authority area, 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. We propose to further 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 with a rating equal to the rating of 

the controllable tie line. 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 net area interchange; how tie line flow is 

scaled or otherwise controlled when calculating simultaneous incremental transfer 

capability; and how to account for long-term firm transmission reservations over 

controllable tie lines. 

168. 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 

 

equipment such as converters, phase shifting transformers, variable frequency 

transformers, etc.
Docket No. RM14-14-000 101

on controllable merchant lines, they shall assume the full capacity of such lines is held by

sellers with long-term firm transmission reservations. 

169. As an initial matter, we reiterate 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.”184 Order No. 697 stated that the SIL study “is a 

study to determine how much competitive supply from remote resources can serve load 

in the study area.”185 The Commission clarified 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.186 However, the exclusion of all study area nonaffiliated 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 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. Therefore, we propose to require sellers to 

include all load associated with balancing authority area(s) within the study area. 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 

 

184 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354 (citing Market-Based 

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

Utilities, Notice of Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,602, at P 77 

(2006)).

185 Id. P 361. 

186 Puget, 135 FERC ¶ 61,254 at Appendix B.
Docket No. RM14-14-000 102

is modeled as part of the study area.

187

 To ensure Submittal 1 is consistent with these 

requirements, we propose to revise Row 8 to read “Adjusted Historical Peak Load”

(instead of “Study area adjusted native load”).

170. We are also looking for consistent, reported load values for all sellers to use in 

preparing SIL studies. Puget, Appendix B, Submittal 1 requires sellers to use FERC 

Form No. 714 load values or explain the source of the data used. Some sellers have 

commented that the load values in their models differ from Form No. 714 data and have 

sought to rely on data from sources other than FERC Form No. 714. We seek industry 

comment on what sources other than FERC Form No. 714 may be appropriate sources to 

rely on in determining historical peak load.

171. We clarify that the values provided in Submittal 1 should generally be supported 

by the submitted seasonal benchmark power flow models. In particular, we expect 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. We propose to update Submittal 1, as reflected in 

 

187 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. RM14-14-000 103

Appendix E to this NOPR, to provide additional clarity on the expected values for certain 

rows.

188

 We propose to post a new version of Submittal 1 on the Commission’s Web site.

c. Simultaneous TTC

172. We propose to define standard guidance for data submittals and representations 

that sellers using the simultaneous TTC method must provide to the Commission. First, 

sellers must provide historical data of actual, hourly, real-time TTC values used for 

operating the transmission system and posting availability on OASIS for each interface 

during each seasonal study period. 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 simultaneous 

TTC values are simultaneously feasible by performing a power flow study that verifies 

that the declared simultaneous TTC value is simultaneously feasible while accounting for 

all internal and external transmission limitations supplied in Appendix E and Puget. 

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. 

173. We reiterate that, in the event there are limited interconnections between first-tier 

markets, the Commission will review evidence that potential loop flow between first-tier 

 

188 See Revised Appendix E, Submittal 1.
Docket No. RM14-14-000 104

areas is properly accounted for in the underlying SIL values on a case-by-case basis.189 

However, we clarify 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. 

174. We seek comment on these proposals.

H. Parts 101 and Part 141 Waivers

1. Current Policy

175. As noted in Order No. 697, the Commission has granted certain entities with 

market-based rate authority, such as power marketers and independent or affiliated power 

producers, waiver of the Commission’s Uniform System of Accounts requirements, 

specifically waiver of Parts 41, 101, and 141 of the Commission’s regulations, except 

§§ 141.14 and 141.15.

190

 The Commission found that the costs of complying with the 

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.191 However, the Commission typically 

 

189 Atlantic Renewables Projects II, 135 FERC ¶ 61,227, at P 9 (2011).

190 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 976, 984. 

191 Id. P 985 (noting that the Commission has “previously stated that Parts 41, 101 

and 141 prescribe certain accounting and reporting requirements that focus on the assets 

that a utility owns, and waiver of these requirements is appropriate where the utility ‘will 

not own any such assets, its jurisdictional facilities will be only corporate and 

 (continued...)
Docket No. RM14-14-000 105

does not grant market-based rate sellers waiver of §§ 141.14 and 141.15 of the 

Commission’s regulations, which address certain reporting requirements applicable to 

hydropower licensees.192

2. Proposal

176. We clarify here 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. 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 sections 4(b), 10(d) and 14 of the

FPA.193 We further note that a licensee’s status as a market-based rate seller under Part II 

 

documentary, its costs will be determined by utilities that sell power to it, and its earnings 

will not be defined and regulated in terms of an authorized return on invested capital’”).

192 See Electron Hydro, LLC, 144 FERC ¶ 61,161, at P 23 (2013).

193 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 

 (continued...)
Docket No. RM14-14-000 106

of the FPA does not exempt it from accounting responsibilities as a licensee under Part I 

of the FPA.194 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.

177. We further 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 

 

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.

194 See Seneca Gen., LLC, 145 FERC ¶ 61,096, at P 23 n.20 (2013) (citing 

Trafalgar Power, 87 FERC ¶ 61,207, at 61,798).
Docket No. RM14-14-000 107

its market-based rate tariff specifies that waiver of Part 141 has been granted, with the 

exception of §§ 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).195 

178. 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 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 hydro 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.

 

195 See Domtar Maine, LLC, 133 FERC ¶ 61,207, at P 23 (2010).
Docket No. RM14-14-000 108

I. Miscellaneous

1. Regional Reporting Schedule

179. Section 35.37(a)(1) of the Commission’s regulations requires Category 2 sellers to 

submit a market power analysis “every three years, according to the schedule contained 

in Order No. 697.”196 The Commission stated in Order No. 697 that Category 2 sellers 

“will be required to file an updated market power analysis based on the schedule in 

Appendix D.”197 Concurrent with the issuance of this NOPR, we will post on the 

Commission’s Web site an updated version of the schedule. Additionally, we propose to 

revise § 35.37(a)(1) as follows:

In addition to other requirements in subparts A and B, a Seller must submit a 

market power analysis in the following circumstances: when seeking market-based 

rate authority; for Category 2 Sellers, every three years, according to the schedule 

contained in Order No. 697, FERC Stats. & Regs. ¶ 31,252posted on the 

Commission’s Web site; or any other time the Commission directs a Seller to 

submit one. Failure to timely file an updated market power analysis will constitute 

a violation of Seller's market-based rate tariff.

180. We also include an updated region map in Appendix D of this NOPR.

2. Affirmative Statement

181. 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 

 

196 18 CFR 35.37(a)(1).

197 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 850.
Docket No. RM14-14-000 109

the relevant market.198 This requirement is codified at § 35.37(e)(4): “In addition, a 

Seller is required 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.”

199

 

In Order No. 697, the Commission stated that the obligation applies both to the seller and 

its affiliates, but is limited to the geographic market(s) in which the seller is located.200 

However, many sellers have not mentioned their affiliates when making their affirmative 

statements. Therefore, we propose to revise § 35.37(e)(4) (which is proposed elsewhere 

in this NOPR to be renumbered as § 35.37(e)(3)), as follows to make clear that the 

affirmative statement requirement applies to the seller and its affiliates:

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 has not erected barriers to entry into the relevant market and will 

not erect barriers to entry into the relevant market.

IV. Information Collection Statement

182. The information collection requirements contained in this proposed rule are 

subject to review by the Office of Management and Budget (OMB) under section 3507(d) 

of the Paperwork Reduction Act of 1995 (PRA).201 The OMB regulations require 

 

198 Id. P 447.

199 18 CFR 35.37(e)(4).

200 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 447.

201 44 U.S.C. 3507(d) (2012).
Docket No. RM14-14-000 110

approval of certain reporting and recordkeeping requirements (collections of information) 

imposed by agency rules.202 Upon approval of a collection of information, OMB will 

assign an OMB control number and expiration date. Respondents subject to the filing 

requirements of this rule will not be penalized for failing to respond to this collection of 

information unless the collection of information displays a valid OMB control number.

183. Comments are solicited on the Commission’s need for this information, whether 

the information will have practical utility, the accuracy of the provided burden estimate, 

ways to enhance the quality, utility, and clarity of the information to be collected, and any 

suggested methods for minimizing the respondent’s burden,203 including the use of 

automated information techniques.

Calculated Burden

184. We propose to clarify and streamline the Commission’s regulations, and to reduce 

the burden on entities seeking to obtain or retain market-based rate authority by revising 

existing market-based rate requirements under Subpart H to Part 35 of Title 18 of the 

Code of Federal Regulations. Specifically, as discussed below, three significant filing 

burdens will be reduced or eliminated by the proposed rule due to (1) eliminating the 

requirement for sellers in an RTO to file indicative screens; (2) creating a threshold for 

 

202 5 CFR 1320.11.

203 The Commission defines burden as the total time, effort, or financial resources 

expended by persons to generate, maintain, retain, or disclose or provide information to 

or for a Federal agency. For further explanation of what is included in the information 

collection burden, reference 5 CFR 1320.3.
Docket No. RM14-14-000 111

reporting new affiliations only if they result in a 100 MW or more cumulative change in 

generation capacity; and (3) discontinuing land acquisition reporting requirements for 

market-based rate sellers. As discussed below, other amendments in the proposed rule 

also are expected to reduce the filing burden on market-based rate sellers, but to a lesser 

extent.

185. Section 35.37 of the Commission’s regulations currently requires market-based 

rate sellers to submit a horizontal market power analysis when seeking to obtain or retain 

market-based rate authority.204 We propose to implement a streamlined procedure that 

will eliminate the requirement 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. 

Eliminating the requirement for RTO sellers to file indicative screens will reduce the 

burden of filing a horizontal market power analysis for a large portion of market-based 

rate sellers when filing updated market power analyses, initial applications for marketbased rate authority, and notices of change in status.

186. We propose to further reduce the filing burden on market-based rate sellers by 

adopting a reporting threshold of a 100 MW cumulative net change in generation 

capacity for reporting changes in status regarding new affiliations. This change applies 

the 100 MW reporting threshold for new generation in 18 CFR 35.42(a)(1) to the 

 

204 18 CFR 35.37.
Docket No. RM14-14-000 112

reporting requirement for new affiliations in 18 CFR 35.42(a)(2). Under this proposed 

change, we expect that market-based rate sellers will file fewer changes in status, instead 

of reporting multiple acquisitions of small newly-affiliated generators in one filing. 

Given that a change in status filing typically includes a transmittal letter and a revised 

asset appendix and may also include indicative screens, we expect this change to reduce 

burdens on market-based rate sellers.

187. Section 35.42(d) of the Commission’s regulations currently requires that all 

market-based rate sellers report on a quarterly basis the acquisition of site(s) that have the 

potential to be developed for new generation capacity of 100 MWs or more.205 The 

Commission proposes to eliminate the burden on all market-based rate sellers by 

discontinuing the quarterly land acquisition reporting requirement in § 35.42(d). The 

Commission also proposes to eliminate the provision in § 35.37(e)(2) requiring reporting 

of sites for generation capacity development as part of the vertical market power analysis.

Other Changes in Burden

188. In addition to the elimination of significant burdens to market-based rate sellers 

discussed above, we propose to revise a number of current market-based rate 

requirements in 18 CFR Part 35 to provide greater clarity to entities seeking to acquire 

and retain market-based rate authority. These revisions are expected to: (1) reduce the 

need for clarification phone calls from market-based rate sellers and subsequent follow-

 

205 18 CFR 35.42(d).
Docket No. RM14-14-000 113

up phone calls from staff; (2) reduce amendments filed to correct errors and the related 

processing delays; and (3) streamline existing requirements, thereby reducing the burden 

in future filings. We estimate that such measures will typically reduce burdens on 

market-based rate sellers. Some simplifications to the existing market-based rate 

requirements may create an initial, minimal one-time implementation burden for marketbased rate sellers when the filing is first submitted. 

189. The Commission is also making a few minor additions to the current requirements. 

These proposed additions include: (a) providing organization charts (for initial 

applications for market-based rate authority, updated market power analyses and notices 

of change in status reporting new affiliations); (b) splitting some entries in Appendix A to 

provide more detail;

206 (c) citing the Order accepting the OATT in Appendix B; and (d) 

amendments to Submittal 2 to account for non-affiliate long-term firm reservations and 

wheel-through transactions.

190. However, any increases in burden (for the initial filing, such as downloading the 

new proposed spreadsheets, as well as ongoing additions) are expected to be greatly 

outweighed by the reduction in burden.

 

206 For example, we propose to split Row A (Installed Capacity) in the existing 

pivotal supplier screen into Row A (Installed Capacity (from inside the study area)) and 

Row A1 (Remote Capacity (from outside the study area)), with similar changes being 

made to currently defined Rows B, E, and F. Similar changes are proposed for the same 

rows in the market share screen.
Docket No. RM14-14-000 114

Public Reporting Burden: The Commission recently issued notices on the burden

estimate for FERC-919.

207

 The estimated total annual burden of 85,444 hours includes:

 Market power analysis in new applications for market-based Rates [18 CFR 

35.37(a)], 53,250 hours;

 Triennial market power analysis in Category 2 seller updates [18 CFR 35.37(a)], 

20,750 hours;

 Quarterly land acquisition reports [18 CFR 35.42(d)], 3,208 hours; and

 Change in status reports [18 CFR 35.42(a)], 8,236 hours.

191. In comparison, the total burden estimate for all market-based rate sellers after the 

Proposed Rule goes into effect is expected to be significantly lower. The total cost for 

market-based rate sellers after revising the market-based rate requirements is expected to 

be as follows:208 

 

207 The Commission issued notices requesting comment in Docket No. IC14-2-

000. See 78 FR 62,006 (Oct. 11, 2013); 79 FR 818 (Jan. 7, 2014). The FERC-919 and 

related burden estimates were approved by OMB on February 27, 2014.

208 Order No. 697 included the burden for Appendix A Parts I and II. The burden 

was not modified when Appendix A Part II was inadvertently omitted in Order 

No. 697-A; the burden related to Appendix A Part II continues to be included in the 

FERC-919.

FERC-919, burden after implementation of proposals in NOPR in Docket No. 

RM14-14
Docket No. RM14-14-000 115

Number of 

Respondents

(A)

Number of 

Responses 

Per 

Respondent

(B)

Total 

Number 

of 

Responses

(A) x (B) 

=(C)

Average 

Burden 

Hours 

per 

Response

(D)

Estimated 

Total 

Annual 

Burden 

Hours

(C)x(D)

New applications 

for market-based 

rates [18 CFR 

35.37], With

Screens 107 1 107 250 26,750

New applications 

for market-based 

rates [18 CFR 

35.37], No 

Screens 106 1 106 120 12,720

Triennial market 

power analysis in 

Category 2 seller 

updates [18 CFR 

35.37], With 

Screens 42 1 42 250 10,500

Triennial market 

power analysis in 

Category 2 seller 

updates [18 CFR 

35.37], No 

Screens 41 1 41 120 4,920

Quarterly land 

acquisition reports 

[18 CFR 35.42(d)] 0 0 0 0 0

Change in status 

reports [18 CFR 

35.42(a)], With 

Screens 13 1 13 250 3,250

Change in status 

reports [18 CFR 

35.42(a)], No 

Screens 224 1 224 20 4,480

TOTAL 62,620
Docket No. RM14-14-000 116

192. After implementation of the proposed changes, the total estimated annual cost 

burden to respondents is $5,497,409.80 [62,620 hours * $87.79209) = $5,497,409.80]. 

This represents a reduction in total annual burden for FERC-919 of 22,824 hours210 (to 

62,620 hours from 85,444 hours) or a 27 percent reduction. 

Title: Proposed Revisions to Market Based Rates for Wholesale Sales of Electric Energy, 

Capacity and Ancillary Services by Public Utilities (FERC-919).

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. 

 

209 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: $74.29/hour

• Electrical Engineer: $60.70/hour

• Lawyer: $128.39/hour

The average hourly cost of the three categories is $87.79 

[($74.29+$60.70+$128.39)/3].

210 This includes reductions for: new applications for market-based rates of 

13,780 hours; triennial market power analysis of 5,330 hours; quarterly land acquisition 

reports of 3,208 hours; and change in status reports of 506 hours.
Docket No. RM14-14-000 117

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 propose to eliminate this requirement under the proposed rule.

Change in Status Reports: On occasion. 

Necessity of the Information: 

Initial Applications: In order to retain 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 authority 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.

Change in Status Reports: The change in status requirement 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 
Docket No. RM14-14-000 118

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. 

Interested persons may obtain information on the reporting requirements by contacting 

the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, 

e-mail: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873]. Please 

send comments concerning the collection of information and the associated burden 

estimates to the Commission, and to the Office of Management and Budget, Office of 

Information and Regulatory Affairs, Washington, DC 20503 [Attention: Desk Officer 

for the Federal Energy Regulatory Commission, phone: (202) 395-4638, fax: (202) 395-

7285]. For security reasons, comments to OMB should be submitted by e-mail to: 

oira_submission@omb.eop.gov. Comments submitted to OMB should include Docket 

Number RM14-14, FERC-919, and OMB Control Number 1902-0234.

V. Environmental Analysis

193. 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.211 The Commission has categorically excluded certain 

 

211 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).
Docket No. RM14-14-000 119

actions from this requirement as not having a significant effect on the human 

environment.212 The actions proposed here fall within the categorical exclusions in the

Commission’s regulations for rules that are clarifying, corrective, or procedural, or do not 

substantially change the effect of legislation or regulations being amended.213 In addition, 

the proposed rule is categorically excluded as an electric rate filing submitted by a public 

utility under sections 205 and 206 of the FPA.214 As explained above, this proposed rule, 

which addresses the issue of electric rate filings submitted by public utilities for marketbased rate authority, is clarifying in nature. Accordingly, no environmental assessment is 

necessary and none has been prepared in this NOPR.

VI. Regulatory Flexibility Act

The Regulatory Flexibility Act of 1980 (RFA)215 194. generally requires a description 

and analysis of proposed rules that will have significant economic impact on a substantial 

number of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a proposed rule and that minimize any significant 

economic impact on a substantial number of small entities. The Small Business 

Administration’s (SBA) Office of Size Standards develops the numerical definition of a 

 

212 18 CFR 380.4.

213 18 CFR 380.4(a)(2)(ii).

214 18 CFR 380.4(a)(15).

215 5 U.S.C. 601-612 (2012).
Docket No. RM14-14-000 120

small business.

216

 The SBA recently revised its size standard for electric utilities 

(effective January 22, 2014) to a standard based on the number of employees, including 

affiliates (from a standard based on megawatt hours).217 Under SBA’s new size 

standards, electric utilities, electric power distribution, and electric bulk power 

transmission and control, and power marketers likely come under one of the following 

categories and associated size thresholds:218

 Hydroelectric power generation, at 500 employees 

 Fossil fuel electric power generation, at 750 employees 

 Nuclear electric power generation, at 750 employees

 Other electric power generation (e.g., solar, wind, geothermal, biomass, and 

other), at 250 employees

 Electric bulk power transmission and control, at 500 employees

 Electric power distribution, at 1,000 employees.

 Wholesale Trade Agents and Brokers,

219 at 100 employees 

 

216 13 CFR 121.101 (2013).

217 SBA Final Rule on “Small Business Size Standards: Utilities,” 78 FR 77343 

(Dec. 23, 2013).

218 13 CFR 121.201, Sector 22, Utilities. 

219 The NAICS category 425120 (Wholesale Electronic Markets and Agents and 

Brokers, within Subsector 425) covers Power Marketers.
Docket No. RM14-14-000 121

Based on U.S. economic census data,220 195. the approximate percentages of small 

firms in these categories vary from 24 percent to 99 percent. However, currently FERC 

does not have information on how the economic census data compares with the specific 

entities affected by this proposed rule using the new SBA definitions.221 Regardless, 

FERC recognizes that the rule will likely impact small electric utilities, electric power 

distribution, electric bulk power transmission and control, and power marketers and 

estimates the economic impact on each entity below.

196. The proposed rule will eliminate some requirements, streamline and clarify others, 

and add a few minimal requirements, while reducing burden on entities of all sizes

(public utilities seeking and currently possessing market-based rate authority). 

Implementation of the proposed rule is expected to reduce total annual burden by 

27 percent to the industry. However, the number of filings with the Commission will 

decrease only slightly because the only filings that are proposed to be eliminated are the 

 

220 Data and further information are available from SBA at 

http://www.sba.gov/advocacy/849/12162.

221 For utilities in the SBA’s subsector 221, the previous SBA definition stated that 

“[a] firm is small if, including its affiliates, it is primarily engaged in the generation, 

transmission, and/or distribution of electric energy for sale and its total electric output for 

the preceding fiscal year did not exceed 4 million megawatt hours.” Using the previous 

SBA definition and EQR data from Quarter 3 of 2012 through Quarter 2 of 2013, 678 of 

the 1,903 sellers with market-based rate authority potentially affected by the proposed 

rule would have qualified as small entities. For this estimate, power marketers are 

included with utilities. 
Docket No. RM14-14-000 122

Quarterly Land Acquisition Reports, which we estimate account for four percent of the 

total annual burden on the industry. 

As discussed in Order No. 697,222 197. current regulations regarding market-based rate 

sellers under Subpart H to Part 35 of Title 18 of the Code of Federal Regulations exempt 

many small entities (using SBA’s former definition of a small entity not exceeding 

4 million megawatt hours) from significant filing requirements by designating them as 

Category 1 sellers.223 Category 1 sellers are exempt from triennial updates and may use

simplifying assumptions, such as assuming no competing imports, that the Commission 

allows sellers to use in submitting their horizontal market power analysis. 

198. No longer requiring RTO sellers to file indicative screens will reduce the burden 

on all sellers in RTOs, including small entities in RTOs. The proposed rule also serves to 

clarify existing requirements, such as clarifying that sellers with fully-committed 

generation may submit an explanation that their generation is fully committed in lieu of 

submitting indicative screens. Such clarification may be particularly helpful to small 

entities as many small entities have fully-committed generation.

199. By adopting a reporting threshold of a 100 MW cumulative change in generation 

capacity for reporting changes in status regarding new affiliations, the Commission 

 

222 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 1126-1129.

223 Category 1 Sellers are power marketers and power producers that own or 

control 500 MW or less of generating capacity in aggregate and that are not affiliated 

with a public utility with a franchised service territory. In addition, Category 1 sellers 

must not own or control transmission facilities, and must present no other vertical market 

power issues. 18 CFR 35.36(a)(2).
Docket No. RM14-14-000 123

expects a reduction in the frequency of notice of change in status filings, which will 

necessarily reduce the burden on market-based rate sellers, including small entities.

200. The Commission is proposing to discontinue the land acquisition reporting 

requirements, which eliminates the need to submit such filings altogether. By so doing, 

the reduction in burden will be across all market-based rate sellers, including small 

entities.

201. The additional one-time burden to market-based rate sellers is expected to cause a 

minimal increase in burden only during initial implementation, and will decrease future 

burdens by allowing a streamlined analysis in subsequent filings. The additional ongoing 

requirements (such as providing organization charts, providing details on the components 

in Appendix A within and outside the study area, and reporting non-affiliate long-term 

reservations and wheel-through transactions in Submittal 2) represent information that is 

already available to filers and should result in little additional burden.

202. The changes to the Commission’s regulations for market-based rate sellers are 

estimated to cause a reduction of 27 percent in total annual burden to all sellers, including 

small entities. 

203. Accordingly, the Commission certifies that the revised requirements set forth in 

this NOPR will not have a significant economic impact on a substantial number of small 

entities, and no regulatory flexibility analysis is required. The Commission finds that the 

regulations adopted here should not have a significant impact on small businesses.
Docket No. RM14-14-000 124

VII. Comment Procedures

204. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due [INSERT DATE 60 

days after publication in the FEDERAL REGISTER]]. Comments must refer to 

Docket No. RM14-14-000, and must include the commenter's name, the organization 

they represent, if applicable, and their address in their comments.

205. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing.

206. Commenters that are not able to file comments electronically must send an 

original of their comments to: Federal Energy Regulatory Commission, Secretary of the 

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

207. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters.
Docket No. RM14-14-000 125

VIII. Document Availability

208. 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, D.C. 20426.

209. 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.

210. User assistance is available for eLibrary and the Commission’s Web site during 

normal business hours from the Commission’s Online Support at 202-502-6652 (toll free 

at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 

Room at (202) 502-8371, TTY (202)502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov.
Docket No. RM14-14-000 126

List of subjects in 18 CFR Part 35

Electric power rates, Electric utilities, Reporting and recordkeeping requirements.

By direction of the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket No. RM14-14-000 127

In consideration of the foregoing, the Commission proposes to amend 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 
Docket No. RM14-14-000 128

Seller's generation assets; and 

(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 Web site.”

b. Revise paragraphs (a)(2) and (c)(4).

c. Add paragraphs (c)(5) and (c)(6).

d. Remove paragraph (e)(2) and redesignate paragraphs (e)(3) through (4) as 

paragraphs (e)(2) through (3), respectively.

e. Revise redesignated paragraph (e)(3).

The revisions and additions read as follows:

§ 35.37 Market Power analysis required.

(a)(1) * * *

(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 upstream owners, 

energy subsidiaries and energy affiliates. 

* * * * *

(c) * * *
Docket No. RM14-14-000 129

(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 

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 Web site.

(6) In lieu of submitting the indicative screens, Sellers in regional transmission 

organization and independent system operator markets with Commission-approved 

market monitoring and mitigation must include a statement that they are relying on such

mitigation to address any potential horizontal market power concerns.

* * * * *

(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).
Docket No. RM14-14-000 130

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) * * *

(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 relevant geographic market (including generation in the 

relevant geographic market and generation in any markets that are first tier to the 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 

nameplate capacity in any relevant geographic market (including generation in the 
Docket No. RM14-14-000 131

relevant geographic market(s) and generation in any markets that are first tier to the 

relevant geographic market(s)); 

(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 

Seller’s prior and new corporate structures indicating all upstream owners, energy 

subsidiaries and energy affiliates unless the Seller demonstrates that the change in status 

does not affect the corporate structure of the Seller’s affiliations.
Docket No. RM14-14-000 132

5. Appendix A of subpart H is revised to read as follows:

Appendix A: Standard Screen Format (Data provided for illustrative purposes only)

Part I – Pivotal Supplier Analysis 

Applicant-> Company X, LLC (TO)

Market -> Company X BAA

Date of Filing -> 0-Jan-00 Don't Enter Values (Outlined cell)

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 (Sum A,A1,B,B1,C,D,E,E1,F,F1,G,H,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 (SUM L,M) 300

P Net Uncommitted Supply (K-O) 2,540

Q Seller's Uncommitted Capacity (Sum A,A1,B,B1,C,D,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. RM14-14-000 133

Appendix A: Standard Screen Format (Data provided for illustrative purposes only)

Part II – Market Share Analysis

Applicant-> Company X, LLC (TO)

Study Area -> Company X BAA

Data Year -> Don't Enter Values (Outlined cell)

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 (Sum H, K, L,L1,M,M1,N,O,P) 1,910 1,460 2,450 1,260

R Seller's Uncommitted Capacity (Sum A,A1,B,B1,C,D,E,G,J) 210 90 290 150

S Total Seasonal Uncommitted Capacity (Sum 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 (Sum 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. RM14-14-000 134

6. Appendix B of subpart H is revised to read as follows:

Appendix B: 

 Market-Based Rate Authority and Generation Assets

This is an example of the required appendix listing the filing entity and all its energy affiliates and their associated assets which should be submitted with all market-based rate filings. 

Market-Based Rate Authority and Generation Assets

Market / 

Balancing 

Authority 

Area

Geographic Region 

 Electric Transmission Assets and/or Natural Gas Intrastate Pipelines and/or Gas Storage Facilities

Filing Entity and 

its Energy 

Affiliates 

Cite to order 

accepting OATT 

or granting 

OATT waiver

Asset Name 

and Use Owned By Controlled By

Date 

Control 

Transferred

Market / 

Balancing 

Authority 

Area

Geographic Region Size (length 

and kV)

Location

In-Service Date

Capacity Rating 

(MW): Nameplate, 

Seasonal, or FiveYear Average

Location

Filing Entity and 

its Energy 

Affiliates 

Docket # where 

MBR authority 

was granted

Generation 

Name

Owned By Controlled 

By

Date 

Control 

Transferred
Docket No. RM14-14-000 135

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. RM14-14-000 136

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. RM14-14-000 137

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

-14-000 138

Appendix E

Study Period: December 1, 20XX to November 30, 20XX

Winter Spring Summer Fall Winter Spring Summer Fall

Row 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

Submittal 1: Summary Table of the Components Used to Calculate SIL Values 

Table 1: SIL Computation 

Name of Home BAA/Market Name of First-Tier BAA 
Docket No. RM14-14-000 139

Winter Spring Summer Fall Winter Spring Summer Fall

Description of Remote Resource (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)

Affiliates

1 MW Share of Remote Plant #1 100 - 100 - 50 50 50 50

2 MW Share of Remote Plant #2 50 50 50 50 100 - 100 - 

3 MW Share of Remote Plant #3 60 - 60 - - 50 - 50

4

Purchased Power Agreement where the energy 

is imported into the study area with long-term 

firm reservations

100 100 100 100 80 80 80 80

5

Wheel through transactions to serve first-tier area 

load embedded in the study area using first-tier 

generation

6 Sum of affiliated long-term firm reservations 310 150 310 150 230 180 230 180

Non-Affiliates

7 MW Share of Remote Plant #1 100 - 100 - 50 50 50 50

8 MW Share of Remote Plant #2 50 50 50 50 100 - 100 - 

9 MW Share of Remote Plant #3 60 - 60 - - 50 - 50

10

Purchased Power Agreement where the energy 

is imported into the study area with long-term 

firm reservations

100 100 100 100 80 80 80 80

11

Wheel through transactions to serve first-tier area 

load embedded in the study area using first-tier 

generation

12 Sum of non-affiliated long-term firm reservations 310 150 310 150 230 180 230 180

13

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 Name of First-Tier BAA 

Table 2: Long-Term Firm Transmission Reservations

Submittal 2: Identify Long-Term Firm Transmission Reservations Used to Import Power from Generating

 Resources in the First-Tier Area to Serve Native Load in the Study Area