155 FERC ¶ 61,188

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM14-14-001; Order No. 816-A]

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

Electric Energy, Capacity and Ancillary Services by Public Utilities

(Issued May 19, 2016)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Order on Rehearing and Clarification.

SUMMARY: The Federal Energy Regulatory Commission is denying requests for

rehearing and granting, in part, clarification of its determinations in Order No. 816, which

amended its regulations that govern market-based rate authorizations for wholesale sales

of electric energy, capacity, and ancillary services by public utilities pursuant to the

Federal Power Act.

EFFECTIVE DATE: This rule will become effective [60 days after publication in the

FEDERAL REGISTER].

FOR FURTHER INFORMATION CONTACT:

Greg Basheda (Technical Information)

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6479
Docket No. RM14

-14-001-2-

Carol Johnson (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8521

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

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

Capacity and Ancillary Services by Public Utilities

Docket No. RM14-14-001

ORDER NO. 816-A

ORDER ON REHEARING AND CLARIFICATION

TABLE OF CONTENTS

Paragraph Numbers

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

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

A. Sellers with Fully Committed Long-Term Generation Capacity.....................................12.

B. Reporting of Long-Term Firm Purchases ........................................................................18.

C. Clarification of the Definition or Duration of Long-Term Firm Transmission

Reservations...........................................................................................................................26.

D. Notices of Change in Status.............................................................................................29.

E. New Affiliation and Behind-the-Meter Generation .........................................................38.

F. Corporate Organizational Charts......................................................................................45.

G. Part 101 Waivers..............................................................................................................48.

H. Capacity Ratings ..............................................................................................................52.

I. Inputs to Electric Power Production..................................................................................55.

J. Transmission/Natural Gas Assets Sheet............................................................................58.

K. Long-Term Firm Power Purchases List ...........................................................................60.

L. Generation Assets Sheet, Rows [B] and [H] ....................................................................62.

III. Information Collection Statement .......................................................................................65.

IV. Document Availability ........................................................................................................68.

V. Effective Date .......................................................................................................................71.
155 FERC ¶ 61,188

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Norman C. Bay, Chairman;

 Cheryl A. LaFleur, Tony Clark,

 and Colette D. Honorable.

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

Capacity and Ancillary Services by Public Utilities

Docket No. RM14-14-001

ORDER NO. 816-A

ORDER ON REHEARING AND CLARIFICATION

(Issued May 19, 2016)

I. Introduction

1. On October 16, 2015, the Federal Energy Regulatory Commission (Commission)

issued Order No. 816,1 which amended its regulations that govern market-based rate

authorizations for wholesale sales of electric energy, capacity, and ancillary services by

public utilities pursuant to the Federal Power Act (FPA). In this order, we address

requests for rehearing and clarification of Order No. 816.2

 

1

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

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

No. 816, FERC Stats. & Regs. ¶ 31,374 (2015) (Final Rule).

2 Order No. 816 became effective on January 28, 2016. On December 23, 2015,

upon consideration of requests for a stay of the corporate organizational chart

(continued...)
Docket No. RM14-14-001 - 2 -

2. Nine requests for rehearing and clarification were filed.3 The requests for

rehearing and clarification concern the following topics: sellers with fully committed

long-term generation capacity; the reporting of long-term firm purchases; the definition

or duration of long-term firm transmission reservations; notices of change in status; new

affiliation and behind-the-meter generation; corporate organizational charts; and waiver

of Part 101 of the Commission’s regulations.4

3. In this order, in most respects, we affirm the Commission’s determinations made

in Order No. 816. However, regarding some issues, we provide clarification. 

4. Specifically, as discussed further below, we deny rehearing regarding the

requirement to include the expiration date of the contract when a seller claims that its

capacity is fully committed. To the extent that the expiration date is not known at the

time a seller files for market-based rate authority, we confirm that a subsequent filing to

 

requirement, the Commission issued an order granting an extension of time such that

market-based rate applicants and sellers would not be required to comply with the

corporate organizational chart requirement prior to the issuance of an order on the merits

of the requests for rehearing. Refinements to Policies and Procedures for Market-Based

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

Utilities, 153 FERC ¶ 61,337 (2015).

3

The requests for rehearing and clarification were filed by the following entities: 

EDF Renewable Energy, Inc. and E.ON Climate & Renewables North America LLC (IPP

Developers); Edison Electric Institute (EEI); Electric Power Supply Association (EPSA);

Invenergy Thermal Development LLC and Invenergy Wind Development LLC

(Invenergy); National Hydropower Association (NHA); NextEra Energy, Inc. (NextEra);

Southern California Edison Company (SoCal Edison); Southern Company Services, Inc.

(Southern); and Transmission Access Policy Study Group (TAPS).

4

18 CFR pt. 101 (2015).
Docket No. RM14-14-001 - 3 -

report the contract expiration date will be treated as an informational filing rather than as

an amendment to a pending application.

5. We grant clarification regarding the requirement for applicants within a regional

transmission organization or independent system operator (RTO/ISO) market to report all

long-term firm energy and capacity purchases from generation capacity located within

the RTO/ISO market if the generation is designated as a resource with capacity

obligations. We clarify that this requirement does not apply if the generation is from a

qualifying facility exempt from section 205 of the FPA. In addition, we affirm that a

market-based rate seller must list all of its long-term firm power purchases in its asset

appendix, Appendix B, even if it does not have market-based rate authority in its home

balancing authority area.

6. We clarify that the Commission did not intend to change the definition of longterm firm transmission reservations in Order No. 816 and clarify that long-term firm

transmission reservations are longer than 28 days.

7. Regarding the Commission’s 100 megawatt (MW) threshold for the requirement

to report new affiliations, we affirm the determinations made in Order No. 816 but 

clarify which markets would be a seller’s relevant geographic market for purposes of the

100 MW threshold reporting requirement. We also deny a rehearing request to find that
Docket No. RM14-14-001 - 4 -

capacity in first-tier markets5be included for determining the 100 MW change in status

threshold.

8. We affirm the Commission’s determination in Order No. 816 that sellers are not

required to include behind-the-meter generation in the 100 MW change in status

threshold, the 500 MW Category 1 seller status threshold, or to include such generation in

the asset appendices and indicative screens.

9. Additionally, we clarify that a hydropower licensee that otherwise sells power

only at market-based rates will not be subject to the full requirements of the Uniform

System of Accounts as a consequence of filing a cost-based reactive power tariff with the

Commission, and may satisfy the requirements in Part 101 of the Commission’s

regulations by complying with General Instruction 16 of the Uniform System of

Accounts.

10. We also provide clarification regarding other aspects of the Final Rule, including

revisions to regulatory text and instructions in the asset appendix to ensure consistency

with the Commission’s determinations in the Final Rule.

11. Further, as discussed below, we grant an additional extension of time such that

market-based rate applicants and sellers will not be required to comply with the corporate

organizational chart requirement until the Commission issues an order at a later date.

 

5 We clarify that for purposes of this order, the term “first-tier markets” includes

all first-tier areas, whether they are a balancing authority area or an RTO/ISO market.
Docket No. RM14-14-001 - 5 -

II. Discussion

A. Sellers with Fully Committed Long-Term Generation Capacity

1. Final Rule

12. In Order No. 816, the Commission clarified that sellers may explain that their

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

fully committed, in lieu of submitting indicative screens, in order to satisfy the

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

instances where all generation owned or controlled by a seller and its affiliates in the

relevant balancing authority areas or markets (including first-tier markets) is fully

committed. The Commission clarified that to qualify as fully committed, a seller must

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

its affiliates for one year or longer. The Commission also adopted the proposal that

sellers claiming that all of their relevant capacity is fully committed must provide the

following information: the amount of generation capacity that is fully committed, the

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

the contract, and a representation that the contract is for firm sales for one year or longer.6 

13. In response to NextEra’s concern that at the time a seller files for market-based

rate authority, the expiration date may be unknown, the Commission stated that if a

contract expiration date is unknown at the time of the market-based rate filing, the seller

 

6 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 39.
Docket No. RM14-14-001 - 6 -

must, within 30 days of the date becoming known, submit an informational filing, in the

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

Commission of the contract expiration date. In response to another commenter’s remark

that the expiration date is reported separately in electric quarterly report (EQR) filings,

the Commission noted that many contracts reported in EQR filings do not include

expiration dates and determined that it would require expiration date information in order

to show that generation capacity is fully committed.7

2. Requests for Rehearing

14. NextEra requests rehearing of the Commission’s determination concerning sellers

with fully committed long-term generation capacity, stating that the Commission erred in

requiring a market-based rate seller to report the expiration date of a long-term contract to

the Commission within 30 days of the date being known, rather than simply in an EQR

filing.8 NextEra contends that the Commission erred by failing to set forth an

explanation of the specific after-the-fact need for the contract expiration date, as the seller

is also required to provide the length of the long-term contract in order to demonstrate

that it has no uncommitted capacity.9 NextEra states that if the Commission concludes

that there is an actual need for this information given that after-the-fact reporting means

 

7

Id. P 44.

8 NextEra Rehearing Request at 2.

9

Id. at 12.
Docket No. RM14-14-001 - 7 -

that the expiration date can only be used in an ex post analysis, the Commission should

clarify that it will permit sellers to provide the information to the Commission either

through an EQR submission or on an after-the-fact basis.10 NextEra states that to the

extent that a seller informs the Commission of the contract expiration date within 30 days

of the date becoming known, the Commission should clarify that it will treat such filings

as informational filings rather than as amendments to pending applications.11

3. Commission Determination

15. The Commission stated in Order No. 816 that sellers claiming that capacity is fully

committed must provide, among other things, the length of the long-term contract and the

expiration date of the contract. The same information must be provided for long-term

firm sales of affiliated generation capacity located in the relevant balancing authority

areas or markets, including first-tier markets. Including this information in the record of

a seller’s market-based rate filing is necessary so that a seller’s claims of fully committed

capacity can be verified as needed.

16. In Order No. 816, the Commission addressed comments submitted by NextEra

regarding contract expiration dates. In consideration of NextEra’s contention that the

expiration date may be unknown at the time a seller files for market-based rate

 

10 Id. at 13.

11 Id. at 14.
Docket No. RM14-14-001 - 8 -

authority,12 the Commission determined that, in such instances, the seller must follow up

with an informational filing to inform the Commission of the contract expiration date,

within 30 days of the date becoming known.13

17. In its request for rehearing, NextEra questions the necessity of requiring the

expiration date given that sellers are required to provide the length of the contract. We

continue to believe that the expiration date is an important piece of information for sellers

to provide. The expiration date provides the Commission with a specific date as to when

the affected generation capacity may become uncommitted and the expiration date allows

the Commission to verify the information previously provided by the seller for purposes

of the Commission’s ex ante analysis of the seller’s potential market power. With regard

to NextEra’s argument that the Commission erred in requiring the market-based rate

seller to report the expiration date of a contract to the Commission within 30 days of the

date being known, rather than in an EQR filing, we note that, as the Commission stated in

Order No. 816, many contracts reported in EQR filings do not include expiration dates.14 

Finally, consistent with Order No. 816, we grant NextEra’s request that the Commission

clarify that filings reporting contract expiration dates in support of a seller’s claim that

 

12 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 38.

13 Id. P 44.

14 Id.
Docket No. RM14-14-001 - 9 -

capacity is fully committed will be treated as informational filings rather than as

amendments to filings.15

B. Reporting of Long-Term Firm Purchases

1. Final Rule

18. The Commission adopted the proposal to report in the indicative screens long-term

firm purchases of capacity and/or energy that have an associated long-term firm

transmission reservation. The Commission stated that requiring applicants under the

market-based rate program to report all of their long-term firm purchases of energy

and/or capacity, regardless of whether the applicant has operational control of the

generation capacity supplying the purchased power, will improve the accuracy of the

indicative screens.

16

 The Commission stated that long-term firm power purchase

agreements that are reported in the indicative screens also should be reported in the asset

appendix, Appendix B, and created a separate sheet in Appendix B specifically for

applicants to report all such long-term firm purchases.17 

19. The Commission stated that the requirement that applicants only include long-term

firm power purchase agreements in their indicative screens if they have an associated

long-term transmission reservation will not apply within RTO/ISO markets if that

 

15 Id.

16 Id. P 130.

17 Id. P 139.
Docket No. RM14-14-001 - 10 -

RTO/ISO does not have long-term firm transmission reservations or their equivalent. 

Instead, applicants in such RTO/ISO markets will be required to report all long-term firm

energy and/or capacity purchases from generation capacity located within the RTO/ISO

market if the generation is designated as a network resource or as a resource with

capacity obligations.18

2. Requests for Rehearing

20. SoCal Edison and NextEra seek clarification with regard to the reporting of longterm firm purchases.

21. SoCal Edison seeks clarification that the requirement to report all long-term firm

energy and/or capacity purchases from generation capacity located within the RTO/ISO

market if the generation is designated as a resource with capacity obligations does not

apply if the generation is a qualifying facility exempt from section 205 of the FPA. 

SoCal Edison asserts that there is no reason why an applicant that holds a long-term

contract with a qualifying facility exempt from FPA section 205 should have to report

that in the appendix and screens, even if the facility has capacity obligations, when

affiliate-owned exempt qualifying facilities would be excluded from the reporting

requirement.19

 

18 Id. P 145.

19 SoCal Edison Rehearing Request at 2.
Docket No. RM14-14-001 - 11 -

22. NextEra seeks clarification related to the necessity of reporting long-term power

purchases in the asset appendix, Appendix B, by entities that do not have market-based

rate authorization in their balancing authority area and as a result are not required to

submit indicative screens.

20

 NextEra states that in Order No. 816, the Commission stated

that long-term firm power purchase agreements that are reported in the indicative screens

also should be reported in the asset appendix. NextEra states that based on this

statement, NextEra understands that the Commission will not require the inclusion of

long-term power purchase agreements if a seller does not have market-based rate

authority in its balancing authority area, but instead makes only cost-based sales.21 

NextEra asks the Commission to confirm that the inclusion of such information is only

required for companies that have market-based authority in the relevant geographic

market.22

3. Commission Determination

23. We grant SoCal Edison’s requested clarification. Applicants purchasing energy

and/or capacity from a qualifying facility that is exempt from section 205 of the FPA

under a long-term firm power purchase agreement do not need to include such purchases

in their indicative screens or in their asset appendix. In Order No. 816, the Commission

 

20 NextEra Rehearing Request at 2.

21 Id. at 14.

22 Id. at 15.
Docket No. RM14-14-001 - 12 -

determined that qualifying facilities that are exempt from section 205 of the FPA do not

need to be reported in the asset appendix or indicative screens.

23

 Therefore, to ensure

consistency in horizontal market power analyses filed by sellers we clarify that this

exemption applies equally to long-term firm power purchases agreements backed by such

resources.

24. We reject NextEra’s requested clarification. A market-based rate seller must list

all of its generation assets in its asset appendix even if it does not have market-based rate

authority in its balancing authority area or, indeed, even if its generation is fully

committed and it is not submitting any indicative screens. We see no reason to treat

long-term firm power purchase agreements differently than other generation capacity. In

Order No. 816, the Commission determined that long-term firm power purchase

agreements with an associated long-term firm transmission reservation (or that are

capacity resources in RTO/ISO markets) must be reported in a seller’s indicative screens

and asset appendix. Excluding long-term firm power purchase agreements as requested

by NextEra would be inconsistent with that policy. In addition, sellers without marketbased rate authority in their own balancing authority area typically seek market-based

rate authority elsewhere and do so by submitting indicative screens for their first-tier

markets. A seller’s long-term firm power purchase agreements are a resource that would

need to be reflected in the screens for the seller’s first-tier markets. Since these

 

23 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 255.
Docket No. RM14-14-001 - 13 -

agreements are reflected in the screens to the extent that they provide potential exports

from a seller’s balancing authority area to first-tier markets, they should be included in

the seller’s asset appendix. 

25. We also clarify that the generation capacity associated with a unit-specific longterm contract should be reported in the “Notes” portion of the asset appendix. An

example of this will be posted on the Commission’s website.

C. Clarification of the Definition or Duration of Long-Term Firm

Transmission Reservations

1. Final Rule

26. In the Final Rule, the Commission provided clarification on the preparation of

simultaneous transmission import limit (SIL) studies. In discussing SIL studies, the

Commission declined a request to redefine the applicable duration of long-term firm

transmission reservations, stating that it is currently defined as 28 days or longer.24 

2. Requests for Rehearing

27. Southern states that Order No. 816 appears to erroneously refer to long-term firm

transmission reservations as comprising reservations that are 28 days or longer. Southern

maintains that this is contrary to precedent indicating that the expectation for entities

performing SIL studies was that only transmission reservations with a duration longer

than 28 days (i.e., a duration of 29 days and greater) should be considered to be long-term

firm reservations. 

 

24 Id. P 197.
Docket No. RM14-14-001 - 14 -

3. Commission Determination

28. We clarify that the Commission did not intend to change the definition of longterm firm transmission reservations in Order No. 816. We reaffirm prior Commission

guidance that short-term reservations are up to one month and long-term reservations are

greater than one month.25 February is the shortest month, which means that long-term

firm transmission reservations must be longer than 28 days. Thus, we clarify that longterm firm transmission reservations are longer than 28 days. 

D. Notices of Change in Status

1. Final Rule

29. In the Notice of Proposed Rulemaking (NOPR), the Commission proposed to

revise the change in status regulations at 18 CFR section 35.42 to include a 100 MW

threshold for reporting new affiliations. The Commission stated that a market-based rate

seller that has a new affiliation would not be required to file a change in status for an

affiliation with an entity with generation assets until its new affiliations result in a

cumulative net increase of 100 MW or more of nameplate capacity in any relevant

 

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

Ancillary Services by Public Utilities, Order No. 697-B, FERC Stats. & Regs. ¶ 31,285 at

P 25 (2008).
Docket No. RM14-14-001 - 15 -

geographic market.26 In the Final Rule, the Commission adopted the proposed changes to

the change in status requirements of section 35.42 of the Commission’s regulations.27 

30. In the Final Rule, the Commission stated that the 100 MW threshold applies to

each new relevant market (not previously studied) in which a seller and/or its affiliates

acquire a cumulative net increase of 100 MW.28 The Commission clarified that the

phrase “any relevant market” refers to a market in which a seller already has generation

located and acquires an additional 100 MW or accumulates 100 MW or more in a new

market that the seller had not studied previously.29 The Commission also clarified that

the 100 MW threshold does not include generation capacity that can be imported from

first-tier markets.30 The Commission agreed with commenters that generation capacity in

first-tier markets should not be treated the same as capacity located in the seller’s relevant

geographic market/study area.

31

 

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

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

Stats. & Regs. ¶ 32,702, at P 96 (2014) (NOPR).

27 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 251.

28 Id. P 231.

29 Id. P 237.

30 Id. P 18.

31 Id. P 229.
Docket No. RM14-14-001 - 16 -

2. Requests for Rehearing

31. IPP Developers request that the Commission make the following three

clarifications: (1) if an affiliate of a seller acquires or controls 100 MW of generating

capacity (including long-term firm purchases), the seller must submit a notice of change

in status report if that 100 MW is located in the same relevant market that was studied as

the basis for the seller’s grant of market-based rate authority; (2) if an affiliate of the

seller acquires or controls 100 MW or more of generating capacity (including long-term

firm purchases) in a market that is two tiers away or more, the seller is not required to

submit a notice of change in status report; and (3) if an affiliate of the seller acquires or

controls 100 MW or more of generating capacity (including long-term firm purchases) in

a market that is in the first-tier, the seller is not required to submit a notice of change in

status report.32 IPP Developers state that these three clarification requests appear to be a

proper application of the Commission’s statements in Order No. 816. IPP Developers

conclude that a seller does not have a change in status reporting obligation in regard to an

affiliate’s generation in first-tier and beyond areas.

33

 

32. However, IPP Developers state that the following statement in paragraph 238 of

Order No. 816 makes this reporting obligation unclear: “if a seller’s affiliate is granted

market based rate authority, and that results in 100 MW or more of new generation in a

 

32 IPP Developers Rehearing Request at 1-3.

33 Id.
Docket No. RM14-14-001 - 17 -

market, then the seller will have to file a corresponding change in status.”34 IPP

Developers state that “a market” could be any market other than the seller’s studied

relevant market, i.e., affiliate generation in first-tier or beyond markets.35 IPP Developers

state that this statement appears to say that a seller must file a notice of change in status

report regardless of the market in which an affiliate of the seller acquires or controls 

100 MW or more of generating capacity.36

33. IPP Developers state that if the Commission is not inclined to provide the

clarifications above, then IPP Developers request rehearing.37

34. TAPS seeks rehearing of the threshold calculation, arguing that capacity in firsttier markets should be included for determining changes in the 100 MW change in status

threshold.38 TAPS states that in the NOPR, the Commission proposed to clarify that the

“relevant geographic market” for purposes of that 100 MW trigger included generation

capacity that could be imported from first-tier markets.39 TAPS states that the

Commission then reversed the NOPR proposal, stating that it would “exclude markets

 

34 Id. at 3-4 (citing Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 238

(emphasis added)).

35 Id. at 4.

36 Id.

37 Id. at 3.

38 TAPS Rehearing Request at 1.

39 Id. at 4 (citing NOPR, FERC Stats. & Regs. ¶ 32,702 at P 96).
Docket No. RM14-14-001 - 18 -

and balancing authority areas that are first-tier to the seller’s study area.”40 TAPS states

that the Commission erred and should grant rehearing to revise Order No. 816 to include

generation in first-tier markets for purposes of change in status reporting, whether or not

it is supported by a long-term firm transmission reservation.41 Specifically, TAPS states

that the Commission should require sellers to: (1) include first-tier capacity when there is

a long-term transmission reservation associated with the capacity; and (2) include all

other first-tier capacity either in its entirety or, in the alternative, on a pro rata basis

consistent with the inclusion of such generation in market power screens.

42

 

35. TAPS states that the NOPR’s proposal to include first-tier generation capacity is

both simple and adequate.43 TAPS states that the Commission could allow sellers, with

appropriate support, to prorate generation in markets first-tier to the study area in the

same way capacity is assigned pro rata for indicative screen analyses (assuming there are

no firm transmission reservations associated with the first-tier capacity, in which case it

should be accorded its full megawatt value). TAPS states that this approach would be

 

40 Id. at 5 (citing Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 230).

41 Id. at 6.

42 Id. at 5.

43 Id. at 6-7.
Docket No. RM14-14-001 - 19 -

consistent with the methodology used in the indicative screens, but would require more

analysis than reporting of all first-tier capacity for purposes of change in status reports.44

3. Commission Determination

36. We grant clarification regarding IPP Developers’ three examples of the application

of Order No. 816. The scenarios presented by IPP Developers are a proper application of

the Final Rule, assuming that the seller is not a power marketer (i.e., the seller owns

generation). We also grant clarification regarding the Commission’s statement in

paragraph 238 of Order No. 816. In paragraph 238 of Order No. 816, the Commission

stated that “if a seller’s affiliate is granted market-based rate authority, and that results in

100 MW or more of new generation in a market, then the seller will have to file a

corresponding change in status.”45 We clarify that the phrase “in a market” means any

relevant geographic market for the seller at the time of the change in status filing. 

Further, we note that the relevant geographic market for a particular seller depends on

whether the seller is a power producer or a power marketer, whether the seller owns

transmission or is interconnected to an affiliated transmission system, and whether the

seller’s generation is in an RTO/ISO. The relevant markets for a power marketer include

any market where the power marketer’s affiliates own generation. Thus, a power

marketer that does not own any generation itself would need to report a change in status

 

44 Id. at 7.

45 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 238 (emphasis added).
Docket No. RM14-14-001 - 20 -

for a 100 MW net increase in any market where an affiliate owns generation and has been

granted market-based rate authority.46 However, for a power producer, the relevant

geographic market is where the seller’s generation is physically located. Thus, a power

producer would not need to report a 100 MW affiliate net increase in a market where the

power producer itself does not own any generation. Similarly, in traditional (nonRTO/ISO) markets, the default relevant geographic market is “first, the balancing

authority area where the seller is physically located, and second, the markets directly

interconnected to the seller’s balancing authority area.”47 However, “[w]here a generator

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

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

located).”48 For a seller located in an RTO/ISO market, the seller may consider the

 

46 A power marketer with no affiliated generation is a Category 1 seller (exempt

from filing triennial updated market power analysis) in all regions and has no relevant

geographic market. A power marketer that acquires generation via a long-term power

purchase agreement has a relevant geographic market where the power associated with

this agreement is delivered (sinks), not where it originates (unless source and sink are in

the same market, which is often the case). In this scenario, the power marketer is a

Category 1 or 2 seller in the relevant geographic market depending on the MWs

associated with the contract(s). Category 2 sellers must submit triennial update market

power analyses.

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

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

P 232 (2007).

48 Id. P 232 n.217.
Docket No. RM14-14-001 - 21 -

RTO/ISO as the default relevant geographic market.49 In each circumstance, the marketbased rate seller will have to determine whether any 100 MW increase is in a market that

would be a relevant geographic market for that seller.

37. We deny TAPS’s request that capacity in first-tier markets be included for

determining the 100 MW change in status threshold. As the Commission stated in Order

No. 816, when a seller has a change in status in a particular market, it does not need to

include any changes in adjoining first-tier markets in calculating the 100 MW threshold,

even when a purchaser has long-term firm transmission rights to import affiliated

capacity located in a first-tier market. We reiterate that, with respect to the calculation of

the 100 MW threshold, 100 MW located outside of the study area is not equivalent to 

100 MW inside the study area. In addition, requiring sellers to consider generation

capacity in first-tier markets, and prorate generation from the first-tier markets into the

study area, creates uncertainty as to when a seller would trip the 100 MW threshold and

effectively would force a seller to prepare import analyses to determine how much of

their additional first-tier capacity could be imported into the study area. We believe that

the increased burden of preparing such studies would outweigh the potential benefit

gained from receiving additional information about a seller’s affiliated generation. 

 

49 Id. P 235 (noting that a seller may consider the RTO/ISO as the default relevant

geographic market “unless the Commission has already found the existence of a

submarket”).
Docket No. RM14-14-001 - 22 -

E. New Affiliation and Behind-the-Meter Generation

1. Final Rule

38. As stated above, the Commission adopted the NOPR proposal to establish a 

100 MW threshold for reporting new affiliations in change of status filings. The

Commission stated that a market-based rate seller that has a new affiliation will not be

required to file a change in status for an affiliation with an entity with generation assets

until its new affiliations result in a cumulative net increase of 100 MW of capacity in a

relevant geographic market.50 The Commission stated that the 100 MW threshold will be

determined for each relevant geographic market but will not consider generation capacity

additions in first-tier markets.51 

39. The Commission did not adopt the NOPR proposal to count behind-the-meter

generation in the 100 MW change in status threshold and 500 MW Category 1 seller

threshold or to include such generation in the asset appendix and indicative screens.

52

40. The Commission stated that the output of behind-the-meter generation should be

reflected in the load data reported in the FERC Form No. 714, which reflects the fact that

 

50 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 251. The Commission noted

that if a seller files a notice of change in status for another reason, e.g., to report the

entrance into a power purchase agreement of more than 100 MW, the seller should note

that it has a new affiliate with market-based rate authority and include that new affiliate

and any related assets in the seller’s asset appendix. Id. P 251 n.334.

51 Id. P 251.

52 Id. P 252.
Docket No. RM14-14-001 - 23 -

the load is lower than it otherwise would be if a portion of the load were not served by

behind-the-meter generation. The Commission also stated that, since behind-the-meter

generation is netted out of the load data, requiring sellers to count behind-the-meter

generation as installed capacity could result in double-counting a portion of the seller’s

generation capacity. The Commission clarified that behind-the-meter generation that is

consumed on-site by the host load and not sold into the wholesale market, or is not

synchronized to the transmission grid, is not relevant to the Commission’s horizontal

market power analysis.53

2. Requests for Rehearing

41. TAPS requests rehearing and/or clarification, arguing that behind-the-meter

generation that is available to make wholesale sales and that is not reflected as a

reduction in load reported in Form No. 714 should be included in seller reporting

obligations, including the 100 MW change in status threshold, the indicative screens, the

asset appendix, and the 500 MW Category 1 seller status threshold. 

42. Specifically, TAPS states that the Commission should make clear that behind-themeter generation that is not consumed on-site by the host load and reflected in Form 

No. 714 load data must, consistent with the Commission’s duty to assess market power,

be included in seller reporting obligations and indicative screens and category seller

status determinations. TAPS contends that generation that participates in the wholesale

 

53 Id. P 253.
Docket No. RM14-14-001 - 24 -

markets influences a seller’s market power regardless of whether it may be termed

behind-the-meter.54 TAPS argues that even if it were otherwise permissible, the

exclusion for behind-the-meter generation would be arbitrary and capricious. TAPS

states that because Order No. 816 fails to limit the scope of the behind-the-meter

exclusion to that included in load reported in Form No. 714 or not synchronized to the

grid and provides no definition of behind-the-meter generation, sellers are left to their

own devices to determine what is meant by behind-the-meter generation and then to

exclude those resources for purposes of reporting under Order No. 816.55

43. TAPS states that the Commission should clarify that its exclusion of behind-themeter generation was intended to be restricted by its clarification at paragraph 253 of the

Final Rule—that only generation that is reflected in Form No. 714 or not synchronized

would be excludable from generation from market-based rate reporting and market power

screens. Alternatively, TAPS states that the Commission should grant rehearing and: 

(1) adopt its NOPR proposal to include behind-the-meter generation, with El Paso’s

clarification—i.e., that behind-the-meter generation that is not reflected as a decrease in

load on Form No. 714 should be included in seller reporting obligations and all market

 

54 TAPS Rehearing Request at 11.

55 Id.
Docket No. RM14-14-001 - 25 -

power screens; or (2) otherwise avoid creating a behind-the-meter generation blind spot

of undefined proportions in its market power monitoring and assessment regimen.56

3. Commission Determination

44. We deny TAPS’s request for rehearing. As the Commission stated in the Final

Rule, the output of behind-the-meter generation largely should be reflected in the load

data reported in the FERC Form No. 714, which reflects the fact that the load is lower

than it otherwise would be if a portion of the load were not served by behind-the-meter

generation. Accordingly, since behind-the-meter generation is netted out of the load data,

requiring sellers to count behind-the-meter generation as installed capacity could result in

double-counting a portion of some sellers’ generation capacity. Further, the Commission

stated in the Final Rule that behind-the-meter generation not sold into the wholesale

market is not relevant to the Commission’s horizontal market power analysis. Regarding

TAPS’s concern about behind-the-meter generation that is available to make wholesale

sales and is not reflected in load reported in Form No. 714, we believe, at this time, that

this category of generation is relatively limited and that the burden of sellers reporting

this behind-the-meter generation would outweigh the benefits of such reporting. 

Therefore, at this time, we will not require sellers to report this type of generation.

 

56 Id. at 13.
Docket No. RM14-14-001 - 26 -

F. Corporate Organizational Charts

1. Final Rule

45. In the Final Rule, the Commission adopted the proposal to require a seller to

include a corporate organizational chart when filing an initial application for marketbased rate authority, an updated market power analysis, or, in some circumstances, a

notice of change in status reporting new affiliations.57 The Commission revised the

regulatory text in section 35.37(a)(2) and in section 35.42(c) in this regard.

2. Requests for Rehearing

46. Invenergy, SoCal Edison, NextEra, EEI, and EPSA request rehearing and/or

clarification with respect to the requirement to submit corporate organizational charts. 

Parties argue, among other things, that the requirement imposes a substantial

administrative burden on filers and is at odds with the objective of streamlining the

market-based rate filing process.

3. Commission Determination

47. As noted above, upon consideration of requests for a stay of the corporate

organizational chart requirement, the Commission issued an order granting an extension

of time such that market-based rate applicants and sellers would not be required to

comply with the corporate organizational chart requirement prior to the issuance of an

 

57 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 21.
Docket No. RM14-14-001 - 27 -

order on the merits of the requests for rehearing.58 Upon consideration of the concerns

raised by the parties on rehearing regarding this requirement, we grant an additional

extension of time such that market-based rate applicants and sellers will not be required

to comply with the corporate organizational chart requirement until the Commission

issues an order at a later date addressing this requirement. The extension will allow the

Commission more time to fully consider the benefits and burdens associated with the

corporate organizational chart requirement.59

G. Part 101 Waivers

1. Final Rule

48. The Commission clarified that granting waiver of 18 CFR Part 101 under marketbased rate authority does not waive the requirements under Part I of the FPA for

hydropower licensees. In addition, the Commission clarified that hydropower licensees

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

Commission’s regulations (Uniform System of Accounts) by complying with General

Instruction 16 of the Uniform System of Accounts, and confirmed that hydropower

 

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

Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 153 FERC

¶ 61,337 (2015).

59 The Commission continues to consider appropriate mechanisms for

consolidating the Commission’s data collection requirements, including this

organizational chart requirement, with the proposed rulemakings in Docket Nos. RM15-

23 and RM16-3.
Docket No. RM14-14-001 - 28 -

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

the full requirements of the Uniform System of Accounts.60

2. Requests for Rehearing

49. NHA requests clarification that a hydropower licensee that otherwise sells power

only at market-based rates will not be subject to the full requirements of the Uniform

System of Accounts as a consequence of filing a cost-based reactive power tariff with the

Commission.61 Alternatively, NHA requests that the Commission clarify that it will

allow licensees that otherwise sell only at market-based rates to request authorization, on

a case-by-case basis, to continue to rely on General Instruction 16 of the Uniform System

of Accounts at the time a reactive power tariff is filed with the Commission.62

50. NHA argues that the Commission determined in Order No. 697 that “little purpose

would be served to require compliance with accounting regulations for entities that do not

sell at cost-based rates and do not have captive customers.”63 NHA represents that the

Commission has previously found that reactive power tariffs do not have captive

 

60 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 22.

61 NHA Clarification Request at 3-5.

62 Id. at 5.

63 Id. at 3 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 984).
Docket No. RM14-14-001 - 29 -

customers and do not raise the same concerns as other cost-based rate tariffs.64 

Additionally NHA notes that entities with a reactive power tariff and a market-based rate

tariff have been previously granted waiver of Part 101.65

3. Commission Determination

51. We clarify that a hydropower licensee that otherwise sells power only at marketbased rates will not be subject to the full requirements of the Uniform System of

Accounts as a consequence of filing a cost-based reactive power tariff with the

Commission. Such a seller may satisfy the requirements in Part 101 of the Commission’s

regulations by complying with General Instruction 16 of the Uniform System of

Accounts. We find that this clarification is consistent with previous Commission

findings in Order No. 697 and Sunbury, as noted by NHA. We continue to find,

however, that hydropower licensees that have Commission-approved cost-based rates are

required to comply with the full requirements of the Uniform System of Accounts.66 

Additionally, we remind sellers that “previously granted waivers of the accounting

 

64 Id. at 3-4 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 483

(“concerns underlying the affiliate restrictions do not apply to sales of reactive power

because those sales are typically either made to transmission providers so that the

transmission provider can satisfy its obligation to provide reactive power or made by the

transmission provider under its applicable [open access transmission tariff]”)).

65 Id. (citing Sunbury Generation, LLC, 108 FERC ¶ 61,160 (2004) (Sunbury);

Illinois Power Generating Co., 148 FERC ¶ 61,238 (2014) (granting waivers of Parts 41,

101, and 141 of the Commission’s regulations to entities with a cost-based rate reactive

power tariff and a market-based rate tariff)).

66 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 22.
Docket No. RM14-14-001 - 30 -

requirements will continue to be rescinded where a seller is found to have market power

(or where the sellers accepts a presumption of market power) and the seller proposes

cost-based rate mitigation or the Commission imposes cost-based rate mitigation.”67

H. Capacity Ratings

1. Final Rule

52. In the Final Rule, the Commission revised the regulations at 18 CFR section 35.42

relating to the change in status reporting requirements to permit sellers to use nameplate

or seasonal capacity ratings for the 100 MW threshold for most generation and allow

energy-limited generation to use either nameplate or a five-year average capacity factor.68 

The Commission found that solar photovoltaic and solar thermal facilities are energy

limited and determined that, due to their unique characteristics, solar photovoltaic

facilities, unlike other energy-limited facilities, must use nameplate capacity and may not

use five-year average capacity factors.69

2. Request for Rehearing

53. Southern notes the Commission’s determination in the Final Rule permitted sellers

to use nameplate or seasonal capacity ratings for the 100 MW threshold for most

generation. Southern states that the regulatory text accompanying the Final Rule 

includes the phrase “or seasonal” in 18 CFR section 35.42(a)(2)(i) but not in 18 CFR

 

67 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 986.

68 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 232.

69 Id. P 15.
Docket No. RM14-14-001 - 31 -

section 35.42(a)(1). Southern requests that the Commission add the phrase “or seasonal”

to 18 CFR section 35.42(a)(1) to align with the discussion in the Final Rule.70

3. Commission Determination

54. We find that it is appropriate to revise 18 CFR section 35.42(a)(1) to add the

phrase “or seasonal.” Additionally, we are revising both 18 CFR section 35.42(a)(1) and

18 CFR section 35.42(a)(2)(i) to further align the regulations with the discussion in the

Final Rule. Specifically, the revised regulations will indicate that the 100 MW or more

of capacity should be based on nameplate or seasonal capacity ratings and, for energylimited resources, with the exception of solar photovoltaic facilities, the capacity ratings

should be based on nameplate or five-year average capacity factors. These revised

regulations will indicate that for solar photovoltaic facilities, the capacity ratings should

be based on nameplate capacity.

I. Inputs to Electric Power Production

1. Final Rule

55. The Commission considers a seller’s ability to erect other barriers to entry as part

of the vertical market power analysis and, as such, the Commission requires a seller to

provide a description of its inputs to electric power production.71 Section 35.36(a)(4) of

the Commission’s regulations define inputs to electric power production to mean

 

70 Southern Rehearing Request at 7 n.15 (citing Order No. 816, FERC Stats. &

Regs. ¶ 31,374 at P 232).

71 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 6.
Docket No. RM14-14-001 - 32 -

intrastate natural gas transportation, intrastate natural gas storage or distribution facilities,

sites for generation capacity development, physical coal supply sources and ownership of

or control over who may access transportation of coal supplies. 

56. In the Final Rule, the Commission eliminated the requirement that market-based

rate sellers file quarterly land acquisition reports and provide information on sites for

generation capacity development in market-based rate applications and triennial updated

market power analyses. Specifically, the Commission adopted the proposal to revise the

regulations at 18 CFR section 35.42 relating to the change in status reporting

requirements regarding sites for new generation capacity development and also adopted

the proposal to revise the regulations at 18 CFR section 35.37 to remove the requirement

that sellers provide information regarding sites for generation capacity development to

demonstrate a lack of vertical market power. However, no changes to the definition of

inputs to electric power production were made in the Final Rule.

2. Commission Determination

57. In light the determinations made in the Final Rule, we revise our regulations at 

18 CFR section 35.36(a)(4) to remove sites for generation capacity development from the

definition of inputs to electric power production. However, we clarify that the

affirmative statement regarding barriers to entry required in 18 CFR section 35.37(e)(3)

continues to cover sites for generation capacity development.
Docket No. RM14-14-001 - 33 -

J. Transmission/Natural Gas Assets Sheet

1. Final Rule

58. In the NOPR, the Commission proposed to require any seller that has been granted

waiver of the requirement to file an open access transmission tariff (OATT) for its

transmission facilities to report in its Transmission/Natural Gas Assets Sheet the citation

to the Commission order granting the OATT waiver for those transmission facilities.72 

The Commission did not adopt the NOPR proposal in the Final Rule, agreeing with

SoCal Edison that this requirement would not provide useful information in light of

Order No. 807.73 The Commission further 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.”74 

 

72 NOPR, FERC Stats. & Regs. ¶ 32,702 at P 120.

73 Order No. 816, FERC Stats. & Regs. ¶ 31,374 at P 300 (citing Open Access and

Priority Rights on Interconnection Customer’s Interconnection Facilities, Order No. 807,

FERC Stats. & Regs. ¶ 31,367 (2015) (amending Commission regulations to waive the

OATT requirements of section 35.28, the OASIS requirements of Part 37, and the

Standards of Conduct requirements of Part 358, under certain conditions, for entities that

own interconnection facilities)).

74 Id. P 295 (citing Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 378 (“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).”)).
Docket No. RM14-14-001 - 34 -

2. Commission Determination

59. Upon further consideration, we modify the requirement to report in the asset

appendix transmission facilities that have been granted an individual OATT waiver or

that qualify for a blanket waiver under Order No. 807 and find that sellers are no longer

required to include such facilities in their Transmission/Natural Gas Assets Sheet. We

find that the burden of providing information on such facilities outweighs any benefit to

reporting it. For this reason, we eliminate the requirement to report in the

Transmission/Natural Gas Assets Sheet facilities that qualify for blanket waiver of the

OATT requirement under Order No. 807 and those that have been granted an individual

OATT waiver.

K. Long-Term Firm Power Purchases List

1. Final Rule

60. In the Final Rule, the Commission established a new, separate list in the asset

appendix in which market-based rate sellers are to report their Long-Term Firm Power

Purchase Agreements (PPAs).75 The Commission agreed with commenters that the

format of the Generation Assets Sheet was not well suited for reporting long-term firm

purchases.

 

75 Id. P 270.
Docket No. RM14-14-001 - 35 -

2. Commission Determination

61. Subsequent to the issuance of Order No. 816, Commission Staff received

numerous calls from sellers requesting guidance with respect to completing the LongTerm Firm PPAs Sheet. Upon further consideration, we recognize that certain

modifications to this sheet and its instructions are warranted to improve its clarity. To

that end, we are making the following changes. First, we are eliminating the existing

column B, “Docket # where MBR authority was granted” as this is duplicative of

information required elsewhere in the asset appendix. In response to questions as to

whether the “Market/Balancing Authority Area” column was referring to the source or

sink of the transaction, we are adding a column and specifically requesting sellers to

identify both the source and sink of the transaction in separate designated columns. 

Finally, in response to other questions raised by market-based rate filers, we are adding a

column requiring sellers to indicate whether a particular long-term firm purchase

agreement is backed by a specific identified generation unit or by the supplier’s

generation fleet (i.e., a “system” contract). Instructions for the Long-Term Firm PPAs

Sheet have been modified to reflect these changes and to make certain other clean up

edits.

L. Generation Assets Sheet, Rows [B] and [H]

1. Final Rule

62. The Final Rule contained instructions for completing the asset appendix. The

description of Row [B] indicated that, if applicable, sellers should include the docket

number where market-based rate or qualifying facility status was originally granted, and
Docket No. RM14-14-001 - 36 -

that it can be an EL or QF docket number. The description of Row [H] listed the six

market-based rate regions but mistakenly listed the Southeast region twice and failed to

mention the Northwest region.

2. Commission Determination

63. We revise the instructions for Row [B] of the asset appendix to remove references

to EL and QF dockets. This revision does not change the Commission’s determinations

in Order No. 816. Rather, this revision aligns the description and format information

regarding Row [B] with the Commission’s intent that Row [B] contain the docket number

where market-based rate authority was granted.

64. We revise the instructions to Row [H] of the Generation Assets Sheet to delete the

second reference to “Southeast” and replace it with “Northwest.”

III. Information Collection Statement

65. The Office of Management and Budget (OMB) regulations implementing the

Paperwork Reduction Act of 199576 require that OMB approve certain information

collection requirements imposed by an agency.

77

 Upon approval of a collection(s) of

information, OMB will assign an OMB control number and an expiration date. 

Respondents subject to the filing requirements of a rule will not be penalized for failing

 

76 44 U.S.C. 3507(d) (2012).

77 5 CFR 1320.11.
Docket No. RM14-14-001 - 37 -

to respond to these collections of information unless the collections of information

display a valid OMB control number. 

66. The revisions made in Order No. 816 to the information collection requirements

for market-based rate sellers were approved under FERC-919 (OMB Control No. 1902-

0234).78 This order clarifies and makes minor revisions to some aspects of the existing

information collection requirements for the market-based rate program. The changes to

the information collection include:

 removing the need to list transmission facilities in the Transmission/Natural Gas

Assets Sheet that have an OATT waiver or that qualify for the blanket OATT

waiver (a slight burden decrease)

 adding a source/sink column and a column for generation unit/system contract

type to the Long-Term Firm PPAs Sheet (slight burden increases)

 removing column B, “Docket # where MBR authority was granted” from the

Long-Term Firm PPAs Sheet and removing references to “EL” and “QF” in the

instructions for Row [B] of the Generation Assets Sheet (de minimis decreases)

 removing sites for generation capacity development from the definition of

inputs to electric power production at 18 CFR section 35.36(a)(4) (no change to

burden).

 

78 OMB approved the information collection in Order No. 816 on December 22,

2015.
Docket No. RM14-14-001 - 38 -

The Commission estimates that there will be no net change to burden. This Final Rule

will be submitted to OMB for review and approval of a “No Material/Nonsubstantive

Change.” 

Title: Market Based Rates for Wholesale Sales of Electric Energy, Capacity and

Ancillary Services by Public Utilities (FERC-919).

Action: Clarification and 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.

67. Interested persons may obtain information on the reporting requirements by

contacting: Federal Energy Regulatory Commission, 888 First Street, NE, Washington,

DC 20426 [Attention: Ellen Brown, Office of the Executive Director, e-mail: 

DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873]. Comments

concerning the requirements of this rule may also be sent to the Office of Information and

Regulatory Affairs, Office of Management and Budget, Washington, DC 20503

[Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security

reasons, comments should be sent by e-mail to OMB at oira_submission@omb.eop.gov. 

Comments submitted to OMB should refer to FERC-919 and OMB Control Number

1902-0234.

IV. Document Availability

68. 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
Docket No. RM14-14-001 - 39 -

contents of this document via the Internet through FERC's Home Page

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A,

Washington D.C. 20426.

69. From FERC'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. 

70. User assistance is available for eLibrary and the FERC’s website during normal

business hours from FERC 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.

V. Effective Date

71. These regulations are effective [insert date 60 days from publication in Federal

Register for non-major rules and 60 days from the later of the date Congress receives the

agency notice or the date the rule is published in the Federal Register].
Docket No. RM14-14-001 - 40 -

List of subjects in 18 CFR Part 35

Electric power rates, Electric utilities, Reporting and recordkeeping requirements.

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.
Docket No. RM14-14-001 - 41 -

In consideration of the foregoing, the Commission amends Part 35, Chapter I, Title 18,

Code of Federal Regulations, as follows:

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS

1. The authority citation for Part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-

7352.

§35.36 [Amended]

2. Amend § 35.36 as follows:

a. In paragraph (a)(4), remove the comma and add in its place a semicolon.

b. In paragraph (a)(4), remove the phrase “sites for generation capacity

development;”.

3. Amend § 35.42 by revising paragraphs (a)(1) and (a)(2)(i) to 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

capacity based on nameplate or seasonal capacity ratings, or, for solar photovoltaic

facilities, nameplate capacity, or, for other energy-limited resources, nameplate or fiveyear average capacity factors, in any individual relevant geographic market, or of inputs

to electric power production, or ownership, operation or control of transmission facilities;

or
Docket No. RM14-14-001 - 42 -

(2) * * *

(i) Owns or controls generation facilities or has long-term firm purchases of

capacity and/or energy that results in cumulative net increases (i.e., the difference

between increases and decreases in affiliated generation capacity) of 100 MW or more of

capacity based on nameplate or seasonal capacity ratings, or, for solar photovoltaic

facilities, nameplate capacity, or, for other energy-limited resources, nameplate or fiveyear average capacity factors, in any individual relevant geographic market;

* * * * *

4. Revise appendix B to subpart H to read as follows:

Appendix B to Subpart H of Part 35--Corporate Entities and Assets Sample

Appendix
Docket No. RM14-14-001 - 43 -

Instructions for completing the Asset Appendix Sheet: Generation Assets

Column Title Format Description

[A] Filing Entity and its Energy Affiliates Free Form Text

Name of the Filing Entity and its Affiliates. Please use the exact 

name as in the Company Registration database if possible. 

[B] Docket # where MBR authority was 

granted

Text in the form: ERXX-XXX-XXX where "X" 

is a digit If applicable, Docket Number where MBR was originally granted. 

[C] Generation Name (Plant or Unit Name) Free Form Text

Unit Name or if all units in a plant are reasonably similar, a plant 

name. Use EIA-860 or industry standard names to the extent 

possible.

[D] Owned By Free Form Text

Name of the Entity owning the generation unit or plant. Please use 

the same name as in the Company Registration database if possible. 

[E] Controlled By Free Form Text

Name of the Entity that controls the output of the generation unit or 

plant. Please use the same name as in the Company Registration 

database if possible. 

[F] Date Control Transferred MM/YYYY or DD/MM/YY

The date the unit came under the control of the Entity listed in "[E] 

Controlled By." Often it is the date the generation was acquired or 

built.

[G] Location: 

Market/Balancing Authority Area

Free Form Text. For Markets or 

submarkets please use one of the 

abbreviations or names in the next 

column. For balancing authority areas 

please use the NERC-defined name

One of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or 

their designated submarkets (PJM-East, 5004/5005, AP South, 

Connecticut, Southwest Connecticut, New York City, Long Island) or a 

NERC-defined Balancing Authority Area name.

[H] Location: 

Geographic Region Specific Text One of the six MBR regions: Northeast, Southeast, Central, SPP, Northwest, Southwest.

[I] In-Service Date MM/YYYY or MM/DD/YY The date the unit first came into service.

[J] Capacity Rating: Nameplate (MW) Numeric. Either an integer or fixed width 

numeric with one decimal

The nameplate capacity rating of the unit, usually provided by the 

manufacturer, in MWs.

[K] Capacity Rating: Used in Filing (MW) Numeric. Either an integer or fixed width 

numeric with one decimal The capacity rating of the unit(s), in MWs, used in this filing.

[L]

Capacity Rating: Methodology Used in 

[K]: (N)ameplate, (S)easonal, 5-yr 

(U)nit, 5-yr (E)IA, (A)lternative 

A single capital letter (either "N", "S","U","E", or "A") to designate the 

rating methodology of the unit's capacity used in this filing. Describe 

"Alternative" Capacity Rating Method in End Notes Sheet.

[M] End Note Number (Enter text in End 

Notes Sheet) Integer

The number of the explanatory note in End Notes Sheet that refers to 

this entry. The numbers should be ascending integers throughout the 

appendix. If there are three notes in the Generation Assets Sheet, 

then the first end note in the next asset sheet should be four (please 

do not start over with a new numbering sequence).
Docket No. RM14-14-001 - 44 -

Instructions for completing the Asset Appendix Sheet: Long-Term Firm Power Purchase Agreements (PPA)

Column Title Format Description

[A] Filing Entity and its Energy Affiliates Free Form Text

Name of the Filing Entity or affiliate of the Filing Entity that is 

purchasing the energy or capacity.

[B] Seller Name Free Form Text

Name of the Filing Entity that is selling the capacity and/or energy. 

Please use the exact name as in the Company Registration database if 

possible. 

[C] Amount of PPA (MW) Numeric. Either an integer or fixed width 

numeric with one decimal

Contracted amount of the PPA in MW. If the contract is for the entire 

output of a specific generation unit, you may de-rate the unit using 

the same de-rating methodology that is used for generators of the 

same technology elsewhere in the appendix. If this amount is derated please explain in the End Notes Sheet. Energy-only contracts 

must be converted from MWh to MW. Only report contracts one year 

or longer.

[D]

Location: 

Market/Balancing Authority Area 

(Source)

Free Form Text. For Markets or 

submarkets please use one of the 

abbreviations or names in the next 

column. For balancing authority areas 

please use the NERC-defined name

One of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or 

their designated submarkets (PJM-East, 5004/5005, AP South, 

Connecticut, Southwest Connecticut, New York City, Long Island) or a 

NERC-defined Balancing Authority Area name. For “System” PPAs, 

identify all markets and balancing authority areas from which the PPA 

is sourced to the extent the source location(s) is specified in the PPA.

[E] Location: 

Market/Balancing Authority Area (Sink)

Free Form Text. For Markets or 

submarkets please use one of the 

abbreviations or names in the next 

column. For balancing authority areas 

please use the NERC-defined name 

One of the six RTO/ISOs (ISO-NE, NYISO, PJM, MISO, SPP, CAISO) or 

their designated submarkets (PJM-East, 5004/5005, AP South, 

Connecticut, Southwest Connecticut, New York City, Long Island) or a 

NERC-defined Balancing Authority Area name. For all PPAs, identify 

where the capacity and/or energy is delivered.

[F] Location: 

Geographic Region (Sink) Specific Text Same instruction as the Generation Assets Sheet. 

[G] Start Date (mo/da/yr) MM/DD/YY The Start Date of the PPA

[H] End Date (mo/da/yr) MM/DD/YY The End Date of the PPA

[I] Type of PPA (Unit or System) "Unit" or "System"

Enter the text "Unit" if the PPA is from a specific unit such as a wind 

generator selling its output to a utility, or from multiple units at a 

single plant. Please provide the name of the unit or facility supplying 

the PPA in the End Notes Sheet. Enter "System" if the PPA is sourced 

from a utility's or IPP's fleet with different units providing power at 

different times.

[J] End Note Number (Enter text in End 

Notes Sheet) Integer Same instruction as the Generation Assets Sheet. 

Instructions for completing the Asset Appendix Sheet: Transmission/Natural Gas Assets

Column Title Format Description

[A] Filing Entity and its Energy Affiliates Same instruction as the Generation Assets Sheet.

[B]

Cite to order accepting OATT or the 

order approving the transfer of 

transmission facilities to an RTO or ISO

Commission cite to the order accepting the Filing Entity's or its Energy 

Affiliate's current OATT, or the order transferring control of the 

transmission facilities to an RTO/ISO.

[C] Asset Name and Use Free Form Text

Legal name of the facility and brief description of the type of facility 

(i.e. transmission line or gas pipeline).

[D] Owned By Name of the Entity owning the transmission/natural gas assets.

[E] Controlled By Name of the Entity that controls the transmission/natural gas assets.

[F] Date Control Transferred Same instruction as the Generation Assets Sheet.

[G] Market/Balancing Authority Area Same instruction as the Generation Assets Sheet.

[H] Geographic Region Same instruction as the Generation Assets Sheet.

[I]

Size (e.g., length and kV for electric, 

length and diameter for pipelines, and 

capacity for gas storage) 

Free Form Text

Description of the size of the facility in the measures relevant to the 

specific type of facility. For example, for electric "Size" refers to the 

length and kV rating of the transmission line; for gas pipeline "Size" 

refers to the length and diameter of the pipeline; for gas storage 

"Size" refers to the capacity of the facility.

[J] End Note Number (Enter text in End 

Notes Sheet) Same instruction as the Generation Assets Sheet.
Docket No. RM14-14-001 - 45 -

Instructions for completing the Asset Appendix Sheet: End Notes

Column Title Format Description

[A] End Note Number Integer

Should match an End Note number in the Generation Assets, LongTerm Firm PPAs or Transmission/Natural Gas Assets Sheets.

[B]

Sheet (Generation Assets, Long-Term 

Firm PPAs or Transmission/Natural Gas 

Assets)

The words "Generation", "PPA", or 

"Transmission/Natural Gas"

Indicates in which asset sheet the End Note is located.

[C] Explanatory Note Free Form Text Text providing the clarification or explanatory note.

This is an example of the required appendix listing the filing entity and all its energy affiliates and their associated assets, which must be submitted with relevant market-based rate filings. 

Asset Appendix: Generation Assets

[A] [B] [C] [D] [E] [F] [G] [H] [I] [J] [K] [L] [M]

Filing 

Entity and 

its Energy 

Affiliates 

Docket # 

where MBR 

authority was 

granted

Generation 

Name 

(Plant or 

Unit Name)

Owned 

By

Controlled 

By

Date 

Control 

Transferred

Market / 

Balancing 

Authority 

Area

Geographic 

Region 

In-Service 

Date

Capacity 

Rating: 

Nameplate 

(MW)

Capacity 

Rating: Used 

in Filing 

(MW)

Capacity Rating: 

Methodology 

Used in [K]: 

(N)ameplate, 

(S)easonal, 5-yr 

(U)nit, 5-yr (E)IA, 

(A)lternative 

End Note 

Number 

(Enter 

text in 

End 

Notes 

Sheet)

Location

 Asset Appendix: Long-Term Firm Power Purchase Agreements (PPA)

Note:

Energy-only contracts must be converted to MW

Only report contracts one year or longer

[A] [B] [C] [D] [E] [F] [G] [H] [I] [J]

Filing Entity 

and its Energy 

Affiliates 

Seller Name

Amount 

of PPA 

(MW)

Market / 

Balancing 

Authority Area 

(Source)

Market / 

Balancing 

Authority 

Area (Sink)

Geographic 

Region 

(Sink)

Start Date 

(mo/da/yr) End Date (mo/da/yr)

Type of 

PPA 

(Unit or 

System)

End Note 

Number (Enter 

text in End 

Notes Sheet)

Location

Asset Appendix: Transmission/Natural Gas Assets

 Electric Transmission Assets and/or Natural Gas Intrastate Pipelines and/or Gas Storage Facilities

[A] [B] [C] [D] [E] [F] [G] [H] [I] [J]

Size

Filing Entity and 

its Energy 

Affiliates 

Cite to order 

accepting OATT 

or order 

approving the 

transfer of 

transmission 

facilities to an 

RTO or ISO

Asset Name 

and Use Owned By Controlled By

Date 

Control 

Transferred

Market / 

Balancing 

Authority 

Area

Geographic Region 

Size (e.g., 

length and kV 

for electric, 

length and 

diameter for 

pipelines, and 

capacity for gas 

storage) 

End Note Number 

(Enter text in End 

Notes Sheet)

Location
Docket No. RM14-14-001 - 46 -

 Asset Appendix: End Notes

End Notes for Entries in the Generation, Long-Term Firm PPA and Transmission/Natural Gas Assets Sheets

[A] [B] [C]

End Note Number

Sheet 

(Generation, 

PPA or 

Transmission / 

Natural Gas) 

Explanatory Note