163 FERC ¶ 61,041

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM17-2-000; Order No. 844]

Uplift Cost Allocation and Transparency in Markets Operated by Regional Transmission 

Organizations and Independent System Operators

(Issued April 19, 2018)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final Rule

SUMMARY: The Federal Energy Regulatory Commission is revising its regulations to

improve transparency practices for regional transmission organizations (RTO) and 

independent system operators (ISO). The Commission requires that each RTO/ISO

establish in its tariff: requirements to report, on a monthly basis, total uplift payments for 

each transmission zone, broken out by day and uplift category; requirements to report, on 

a monthly basis, total uplift payments for each resource; requirements to report, on a 

monthly basis, for each operator-initiated commitment, the size of the commitment, 

transmission zone, commitment reason, and commitment start time; and the transmission 

constraint penalty factors used in its market software, as well as the circumstances under 

which those factors can set locational marginal prices, and any process by which they can 

be changed. The Commission is withdrawing its proposal to require that each RTO/ISO

that currently allocates the costs of real-time uplift to deviations allocate such real-time 

uplift costs only to those market participants whose transactions are reasonably expected 
Docket No. RM17-2-000 ii

to have caused the real-time uplift costs. 

EFFECTIVE DATE: This rule will become effective 75 days after publication in the 

FEDERAL REGISTER.

FOR FURTHER INFORMATION CONTACT:

Adam Cornelius (Technical Information)

Office of Energy Policy and Innovation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8314

adam.cornelius@ferc.gov

Katherine Scott (Technical Information)

Office of Energy Market Regulation

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-6495

Katherine.Scott@ferc.gov

Colin Beckman (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE

Washington, DC 20426

(202) 502-8049

colin.beckman@ferc.gov

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Kevin J. McIntyre, Chairman;

 Cheryl A. LaFleur, Neil Chatterjee,

Robert F. Powelson, and Richard Glick.

Uplift Cost Allocation and Transparency in Markets 

Operated by Regional Transmission Organizations and 

Independent System Operators

 Docket No. RM17-2-000

ORDER NO. 844 

FINAL RULE

(Issued April 19, 2018)

TABLE OF CONTENTS

Paragraph Numbers

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

II. Background ................................................................................................................. 10.

A. Current RTO/ISO Practices.................................................................................... 12.

1. Reporting Uplift ................................................................................................. 13.

2. Reporting Operator-Initiated Commitments ...................................................... 17.

3. Transmission Constraint Penalty Factors .......................................................... 20.

III. Need for Reform........................................................................................................ 21.

A. Comments............................................................................................................... 23.

B. Determination ......................................................................................................... 27.

IV. Transparency Reforms .............................................................................................. 30.

A. Zonal Uplift Report ................................................................................................ 36.

1. NOPR Proposal................................................................................................... 36.

2. Comments........................................................................................................... 39.

3. Determination ..................................................................................................... 50.

B. Resource-Specific Uplift Report ............................................................................ 63.

1. NOPR Proposal................................................................................................... 63.

2. Comments........................................................................................................... 66.

3. Determination ..................................................................................................... 74.

C. Operator-Initiated Commitments ........................................................................... 83.

1. NOPR Proposal................................................................................................... 83.
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2. Comments........................................................................................................... 87.

3. Determination ..................................................................................................... 99.

D. Transmission Constraint Penalty Factors............................................................. 109.

1. NOPR Proposal................................................................................................. 109.

2. Comments......................................................................................................... 111.

3. Determination ................................................................................................... 121.

E. Other Comments Requested ................................................................................. 123.

1. Reporting of Transmission Outages................................................................. 123.

2. Availability of Market Models ......................................................................... 131.

V. Compliance and Implementation Timelines............................................................. 136.

A. Comments............................................................................................................. 137.

B. Determination ....................................................................................................... 141.

VI. Information Collection Statement ........................................................................... 142.

VII. Environmental Analysis......................................................................................... 146.

VIII. Regulatory Flexibility Act .................................................................................... 147.

IX. Document Availability ............................................................................................ 149.

X. Effective Date and Congressional Notification........................................................ 152.

APPENDIX: List of Short Names/Acronyms of Commenters ........................................ __
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I. Introduction

1. In this Final Rule, the Federal Energy Regulatory Commission (Commission) 

finds that current regional transmission organization (RTO) and independent system 

operator (ISO) practices with respect to reporting uplift payments and operator-initiated 

commitments,1 and RTO/ISO tariff provisions regarding transmission constraint penalty 

factors2 are insufficiently transparent, resulting in rates that are not just and reasonable

for the reasons discussed below. To remedy these unjust and unreasonable rates, we 

require, pursuant to section 206 of the Federal Power Act,3 that each RTO/ISO establish 

in its tariff: (1) requirements to report, on a monthly basis, total uplift payments for each 

transmission zone, broken out by day and uplift category (Zonal Uplift Report); 

(2) requirements to report, on a monthly basis, total uplift payments for each resource 

(Resource-Specific Uplift Report); (3) requirements to report, on a monthly basis, for 

each operator-initiated commitment, the size of the commitment, transmission zone,

commitment reason, and commitment start time (Operator-Initiated Commitment 

Report); and (4) the transmission constraint penalty factors used in its market software, as 

well as the circumstances under which those factors can set locational marginal prices 

 1 As described below, for the purpose of this rule, the Commission defines an 

operator-initiated commitment as a commitment after the day-ahead market for a reason 

other than minimizing the total production costs of serving load.

2 Transmission constraint penalty factors are the values at which an RTO’s/ISO’s 

market software will relax the limit on a transmission constraint rather than continue to 

re-dispatch resources to relieve congestion associated with that constraint. 

3 16 U.S.C. 824e.
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(LMP), and any process by which they can be changed (Transmission Constraint Penalty 

Factor Requirements). 

2. We reach this conclusion for several reasons. RTO/ISO markets can be affected 

by a number of operational challenges such as unplanned transmission and generation 

outages and the need to maintain adequate voltage throughout the system. Limitations in 

the ability of the market software to incorporate all reliability considerations can at times 

result in prices that fail to reflect some of these challenges. In such situations, certain 

resources needed to reliably serve load may not economically clear the market and 

RTOs/ISOs must take out-of-market actions (i.e., operator-initiated commitments) to 

ensure system needs are met. These actions give rise to uplift costs. 

3. Because out-of-market actions and the resulting uplift costs are not reflected in 

market prices, these costs and the reasons for incurring such costs are inherently less 

transparent. Out-of-market actions can at times mask system conditions, which limits the 

ability of competitive electric markets to send appropriate price signals to compensate 

and financially encourage investment in resource attributes that respond to system needs. 

Lack of transparency concerning both uplift costs and operator-initiated actions can also 

limit valuable input from stakeholders, for example, during RTO/ISO transmission 

planning processes, or in committees that review RTO/ISO resource adequacy. Ensuring 

system needs are transparent to market participants is a critical step in finding costeffective solutions to the operational challenges RTOs/ISOs face to support reliable

operations and resilience. Reporting information about uplift and operator initiated 

commitments helps ensure these system needs are transparent to the marketplace.
Docket No. RM17-2-000 - 5 -

4. Although all RTOs/ISOs provide some information regarding the locations and 

causes of uplift and operator-initiated commitments, the information is often highly 

aggregated or lacks detail, and is not consistently reported across markets. Current 

reporting practices regarding uplift and the reasons for making operator-initiated 

commitments do not provide adequate transparency for stakeholders to understand the 

needs of the system and recognize the resource attributes that are required to meet these 

needs. This lack of transparency hinders the ability of market participants to plan for and 

efficiently respond to system needs in a cost-effective manner, resulting in rates that are 

unjust and unreasonable. Improving the availability of information about the location 

and causes of uplift and operator-initiated commitments would enhance market 

participants’ ability to evaluate the need for, and the value of investment in, transmission 

and generation. Increased transparency could also facilitate more informed stakeholder 

discussions that support capacity or transmission planning to address future reliability 

and resilience issues. Additionally, RTO/ISO practices with respect to transmission 

constraint penalty factors can significantly affect clearing prices. Improving transparency 

into such practices would enhance market participants’ understanding of how energy 

prices are formed and thus would enhance their ability to hedge transactions and respond 

to market signals. Finally, increased transparency into uplift payments, operator-initiated 

commitments, and transmission constraint penalty factors will allow market participants

to assess and advocate for improvements to RTO/ISO practices in these areas. Therefore, 

we set forth transparency requirements for each RTO/ISO in this Final Rule. 
Docket No. RM17-2-000 - 6 -

5. We are adopting the transparency proposal in the Notice of Proposed Rulemaking 

(NOPR)4 with the following modifications: (1) change the permissible level of zonal 

aggregation for the Zonal Uplift Report; (2) change the timing of the release of the 

Resource-Specific Uplift Report from within twenty calendar days of the end of each 

month to within ninety calendar days from the end of each month; (3) change the timing 

of the release of the Operator-Initiated Commitment Report from four hours after the 

time of the commitment to within thirty calendar days of the end of each month; and 

(4) change the details to be reported about each operator-initiated commitment. These 

changes will help address concerns expressed by commenters related to the potential 

disclosure of commercially-sensitive information, the burden on RTOs/ISOs of meeting 

the requirements of this Final Rule, and the transparency value of consistent reporting. 

6. The goals of the price formation proceeding are to: (1) maximize market surplus 

for consumers and suppliers; (2) provide correct incentives for market participants to 

follow commitment and dispatch instructions, make efficient investments in facilities and 

equipment, and maintain reliability; (3) provide transparency so that market participants 

understand how prices reflect the actual marginal cost of serving load and the operational 

 4 Uplift Cost Allocation and Transparency in Markets Operated by Regional 

Transmission Organizations and Independent System Operators, 82 FR 9539 (Feb. 7, 

2017), FERC Stats. & Regs. ¶ 32,721, at P 82 (2017) (NOPR). 
Docket No. RM17-2-000 - 7 -

constraints of reliably operating the system; and (4) ensure that all suppliers have an 

opportunity to recover their costs.5

7. The reforms in this Final Rule primarily address the third price formation goal

listed above. Uplift payments reflect the portion of the cost of reliably serving load that 

is not included in market prices. Operator-initiated commitments are made to preserve 

reliability and can affect both market prices and uplift. RTO/ISO practices associated 

with transmission constraint penalty factors, which establish the price level and cost of 

re-dispatch the RTO/ISO is willing to incur to relieve congestion on transmission 

constraints, can affect commitments and market prices. Improved transparency into these 

areas will enable market participants to better understand drivers of market prices and the 

extent to which prices reflect the true marginal cost of reliably serving load. As noted 

above, the uplift and operator-initiated commitment reports will also help market 

participants align their investments in facilities and equipment with the needs of the 

system, thus also addressing the second price formation goal. Finally, such investments, 

as well as market participants’ enhanced ability to understand and suggest changes to 

RTO/ISO uplift and commitment practices, may ultimately shift some of the cost of 

serving load out of uplift and into market prices. Prices that more accurately reflect the 

 5 See, e.g., Price Formation in Energy and Ancillary Services Markets Operated 

by Regional Transmission Organizations and Independent System Operators, Order 

Directing Reports, 153 FERC ¶ 61,221, at P 2 (2015) (Order Directing Reports); Price 

Formation in Energy and Ancillary Services Markets Operated by Regional Transmission 

Organizations and Independent System Operators, Notice Inviting Post-Technical 

Workshop Comments, Docket No. AD14-14-000, at 1 (Jan. 16, 2015).
Docket No. RM17-2-000 - 8 -

cost of serving load have the potential to result in improved market efficiency and 

increased market surplus for consumers and suppliers, thus also addressing the first price 

formation goal. These benefits will help to ensure just and reasonable rates.

8. As discussed below, we require each RTO/ISO to submit a filing with the tariff 

changes needed to implement this Final Rule within 60 days of the Final Rule’s effective 

date, and we require that tariff changes filed in response to this Final Rule become 

effective no more than 120 days after compliance filings are due.

9. Finally, in the NOPR the Commission also proposed to require that each RTO/ISO 

that currently allocates the costs of real-time uplift to deviations allocate such real-time 

uplift costs only to those market participants whose transactions are reasonably expected 

to have caused the real-time uplift costs. As discussed below, we withdraw the uplift cost 

allocation proposal and do not make any requirements related to uplift cost allocation in 

this Final Rule.

II. Background

10. In November 2015, the Commission issued an order that directed each RTO/ISO 

to report on five price formation topics: fast-start pricing; managing multiple 

contingencies; look-ahead modeling; uplift allocation; and transparency.6

 The order 

directed each RTO/ISO to file a report providing an update on its current practices and 

any efforts to address issues in the five topic areas, and responding to specific questions 

 6 Order Directing Reports, 153 FERC ¶ 61,221.
Docket No. RM17-2-000 - 9 -

contained in the order. In the reports filed and subsequent comments, RTOs/ISOs and 

commenters addressed the topic of transparency, which is the subject of this Final Rule.

11. In the instant proceeding, on January 19, 2017, the Commission issued a NOPR 

proposing reforms to improve uplift cost allocation and to enhance transparency. As 

noted above, we withdraw the proposed uplift cost allocation reforms. With respect to 

transparency, the NOPR proposed to require that each RTO/ISO: (1) report total uplift 

payments for each transmission zone on a monthly basis, broken out by day and uplift 

category; (2) report total uplift payments for each resource on a monthly basis; (3) report 

the megawatts (MW) of operator-initiated commitments in or near real-time and after the 

close of the day-ahead market, broken out by zone and commitment reason; and (4) list in 

its tariff the transmission constraint penalty factors, the circumstances under which they 

can set LMPs, and the procedure by which they can be changed temporarily.7 The 

Commission also requested comments on specific aspects of each requirement.

8

 

 7 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 82.

8 A list of commenters and the abbreviated names used for them in this Final Rule 

appears in the Appendix.
Docket No. RM17-2-000 - 10 -

A. Current RTO/ISO Practices

12. In the NOPR, the Commission reviewed the current transparency practices of each 

of the RTOs/ISOs,9 based largely on the reports made by the RTOs/ISOs in response to 

the Commission’s Order Directing Reports.10 We do so again briefly in this Final Rule.

1. Reporting Uplift

13. All RTOs/ISOs report information about uplift payments. However, the extent of 

the information reported varies widely. For example, ISO-NE and NYISO provide 

monthly uplift reports that are generally aggregated across zones and over the month as 

well as daily uplift reports aggregated across their entire systems.

11 MISO provides a 

number of monthly reports to market participants on categories of uplift costs; the reports 

aggregate the uplift data by category and month, and provide historical monthly data for 

comparison.12 MISO also posts a Revenue Sufficiency Guarantee13 Report eight days 

 9 NOPR, FERC Stats. & Regs. ¶ 32,721 at PP 59-66.

10 Order Directing Reports, 153 FERC ¶ 61,221.

11 ISO-NE Comments at 42; ISO-NE, Report on Price Formation Issues, Docket 

No. AD14-14, at 46-47 (ISO-NE Report); NYISO Comments at 5-6; NYISO, Report on 

Price Formation Issues, Docket No. AD14-14, at 56-57, 59 (NYISO Report).

12 MISO, Report on Price Formation Issues, Docket No. AD14-14, at 59-60 

(MISO Report).

13 Revenue Sufficiency Guarantee is a type of uplift in MISO that ensures the 

recovery of the production and operating reserve costs of a resource that has been 

committed and scheduled by MISO in its day-ahead or real-time energy and operating 

reserve markets. See MISO, FERC Electric Tariff, 1.D, Definitions - D (45.0.0); 1.R, 

Definitions - R (48.0.0).
Docket No. RM17-2-000 - 11 -

after the operating day, which includes uplift payments by hour, category, and relevant 

transmission constraint.

14 CAISO aggregates uplift data to its 10 existing local capacity 

requirement areas and reports daily total uplift costs for each month by the market in 

which the uplift is incurred (e.g., day-ahead or real-time), and by the type of costs 

incurred (e.g., start-up costs, minimum load costs or energy bid costs).

15 PJM has 

recently adopted new rules to allow the reporting of daily uplift information by 

transmission zone within seven business days after the end of each month.

16 SPP reports 

uplift information by category with daily granularity.

17

14. RTO/ISO reporting practices are driven, in part, by the time needed to complete 

the settlement process. For example, ISO-NE and PJM report some uplift information 

within three to five business days based on their initial settlement periods, while CAISO 

provides uplift cost information based on its 12-business-day recalculation statement.18 

 14 MISO Comments at 11-12.

15 See CAISO, Monthly Market Performance Report, 

http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=A9180EE4-8972-4F3B9CB8-21D0809B645E. See also CAISO, Report on Price Formation Issues, Docket 

No. AD14-14, at 56 (CAISO Report).

16 PJM, Business Practice Manual 33; PJM Comments at 11-12.

17 SPP, Report on Price Formation Issues, Docket No. AD14-14, at 40 (SPP 

Report).

18 CAISO Report at 58; ISO-NE Report at 64-65; PJM, Report on Price Formation 

Issues, Docket No. AD14-14, at 51 (PJM Report).
Docket No. RM17-2-000 - 12 -

Because of this lag, RTOs/ISOs typically report uplift on a monthly basis, aggregated to a 

zonal or settlement area level.

15. Most RTOs/ISOs cite confidentiality issues as an additional reason for their 

current reporting practices, particularly in zones with few market participants.19 Uplift 

information is typically aggregated to avoid publishing information on individual 

resources. All RTOs/ISOs assert that they are prohibited from publicly revealing 

resource-specific data, as specified in their confidentiality rules.20 Some RTOs/ISOs note 

that they cannot provide information on a more granular basis without changes to their 

confidentiality rules or information policies.21

16. Some uplift information is publicly available. For example, all public utilities and 

certain non-public utilities are required to report uplift payments in the Commission’s 

Electric Quarterly Report (EQR) within 30 days following the end of a quarter. Most 

EQR filers report uplift payments with at least daily granularity. Depending on the 

granularity provided by the filer, and whether the filer reports its EQR as a single 

resource, EQR uplift information can also sometimes identify a specific unit and its 

location. EQR contains a single “uplift” category which does not differentiate between 

 19 ISO-NE Report at 61, 67; NYISO Report at 60-61; PJM Comments at 11; 

PJM Report at 48; SPP Report at 44.

20 CAISO Report at 59; NYISO Report at 58; PJM Report at 50-51; SPP Report 

at 42; ISO-NE Report at 63-64; MISO Report at 58-59.

21 PJM Report at 48; ISO-NE Report at 61.
Docket No. RM17-2-000 - 13 -

different types of uplift (e.g., day-ahead, voltage and local reliability). EQR information 

is available to the public via the Commission’s website.

2. Reporting Operator-Initiated Commitments

17. RTOs/ISOs also vary in the amount, granularity, and timing of information that is 

reported on operator-initiated commitments. For example, CAISO, MISO, and NYISO 

provide information regarding operator-initiated commitments either shortly after the 

operating day or in near real-time. MISO reports the hourly aggregated economic 

maximum MWs of committed resources by commitment reason and relevant constraint in 

near real-time,22 while CAISO reports the daily aggregated megawatt-hours of 

exceptional dispatches23 (which include operator-initiated commitments) by reason 

several days after the operating day.24 Throughout the operating day, NYISO posts 

operational announcements that provide information about individual operator-initiated 

commitments, including the units involved, level of unit commitment, and the reason for 

the commitment, with a reference to the relevant reliability rule, if applicable.

25 

 22 MISO Comments at 16-17.

23 CAISO states that its system operator issues exceptional dispatches to resources 

to address system issues that cannot be addressed by the constraints modeled within the 

market. CAISO Report at 41.

24 See CAISO, Daily Exceptional Dispatch Report, 

http://www.caiso.com/market/Pages/DailyExceptionalDispatch/Default.aspx.

25 NYISO Comments at 8 & n.29; NYISO Report at 56-57 and n.32.
Docket No. RM17-2-000 - 14 -

18. In addition, all RTOs/ISOs provide summary reports of operator-initiated 

commitments over longer time periods. CAISO’s monthly performance report provides 

metrics on exceptional dispatch and other operator actions organized by market (i.e., dayahead or real-time), trade date, reason, or local area.26 CAISO also files a monthly report 

on the frequency and volume of exceptional dispatch, pursuant to directives in previous 

Commission orders.

27 ISO-NE publishes weekly, monthly, and quarterly reports that 

describe notable operational events, but it does not provide any information regarding the 

location or capacity of committed units.

28 ISO-NE also reports the number of units 

committed after the close of the day-ahead market (but not including real-time 

commitments) each day.

29 SPP reports monthly the MWs of operator-initiated 

commitments.

30 

19. PJM states that, although its confidentiality provisions prevent it from reporting 

individual operator-initiated commitments in real-time, it does provide regionally 

aggregated information on uneconomic commitments in the day-ahead market at the end 

of the business day. In addition, PJM posts total capacity committed during the 

 26 CAISO Report at 56.

27 Id. at 56. See also Cal. Indep. Sys. Operator Corp., 131 FERC ¶ 61,100 (2010) 

(clarifying the reporting timeline for reporting exceptional dispatches).

28 ISO-NE Report at 60.

29 Id. at 61-62.

30 SPP Report at 40.
Docket No. RM17-2-000 - 15 -

Reliability Assessment and Commitment period to meet forecasted load and reserves, as 

well as resources committed for transmission constraints, voltage/reactive constraints, or 

conservative operations.

31 ISO-NE also states that its confidentiality provisions prohibit 

reporting of operator-initiated commitments in real-time. 

3. Transmission Constraint Penalty Factors

20. Transmission constraint penalty factors are the values at which an RTO’s/ISO’s 

market software will relax the flow-based limit on a transmission element to relieve a 

constraint caused by that limit rather than re-dispatch resources to relieve the constraint. 

The cost of re-dispatching resources can be described as the re-dispatch price. 

Transmission constraint penalty factors represent the maximum re-dispatch price that the 

system will pay before allowing flows to exceed a given transmission element’s limit.32 

The penalty factors are typically set at levels that are high enough to avoid relaxing 

constraints too frequently, but low enough to avoid extremely expensive re-dispatch 

solutions that are more expensive than the expected cost of exceeding a given 

transmission element’s limit. Although these penalty factors can have significant impacts 

on prices, some RTOs/ISOs do not file the penalty factors with the Commission or make 

public any temporary changes to them. Specifically, PJM and ISO-NE do not include 

 31 PJM Report at 49-50.

32 Transmission constraint penalty factors create a cap on the shadow price of a 

transmission constraint. See Potomac Economics Comments, Docket No. AD14-14-000, 

at 20-21 (Feb. 24, 2015).
Docket No. RM17-2-000 - 16 -

transmission constraint penalty factors in their respective tariffs, but the other RTOs/ISOs 

do.

33 Further, MISO is the only RTO/ISO that details in its tariff how transmission 

constraint penalty factors are changed temporarily.34

III. Need for Reform

21. In the NOPR, the Commission preliminarily found that some existing RTO/ISO 

practices of reporting uplift and operator-initiated commitments are insufficiently 

transparent and may result in unjust and unreasonable rates. Specifically, the 

Commission stated that, while all RTOs/ISOs provide some information regarding the 

locations and causes of uplift and operator-initiated commitments, the information is 

often highly aggregated or lacks detail. The Commission posed, as an example, reports 

that aggregate uplift payments over the month, which can obscure daily trends that allow 

market participants to evaluate the effectiveness of current operating practices of 

RTOs/ISOs. The Commission stated that this lack of transparency hinders the ability of 

market participants to plan and efficiently respond to system needs. The Commission 

reasoned that improving the availability of information about the location and causes of 

uplift and operator-initiated commitments could allow market participants to evaluate the 

need for and the value of investment in transmission and generation, as well as assess 

operator-initiated commitment practices and raise any issues of concern through the 

 33 CAISO, MRTU Tariff §§ 27.4.3.1-27.4.3.2; MISO, FERC Electric Tariff, 

Schedule 28A; NYISO Tariffs, NYISO Markets and Services Tariff § 1.20; SPP, OATT, 

Sixth Revised Volume No. 1, Attachment AE, § 8.3.2, Addendum 1.

34 MISO, FERC Electric Tariff, Schedule 28A; MISO Comments at 19.
Docket No. RM17-2-000 - 17 -

stakeholder process. The Commission posed, as an example, the scenario of releasing 

information about uplift incurred to address a local reliability issue. This information, the 

Commission reasoned, could potentially incent market participants to advocate for 

changes to the RTO’s/ISO’s operational procedures or to undertake investments that 

could resolve the local reliability issue more efficiently. The Commission further 

reasoned that, by helping to incent appropriate market responses to system needs, 

increased transparency could improve market efficiency, and could ultimately reduce the 

level of uplift, thereby resulting in rates that are just and reasonable.35

22. The Commission also preliminarily found that a lack of transparency with respect 

to transmission constraint penalty factors may result in unjust and unreasonable rates. 

Specifically, the Commission stated this lack of transparency may make it difficult for 

market participants to hedge transactions appropriately or to effectively assess RTO/ISO 

changes to transmission constraint penalty factors and raise concerns through the 

stakeholder process.

36

A. Comments

23. Several commenters agree with the Commission’s preliminary finding in the 

NOPR that transparency reform is needed. Appian Way states that greater transparency 

will allow issues to be resolved more quickly and efficiently in the contexts of 

 35 NOPR, FERC Stats. & Regs. ¶ 32,721 at PP 77-79.

36 Id. P 80.
Docket No. RM17-2-000 - 18 -

enforcement and stakeholder advocacy.

37 ELCON states that uplift payments and the

reasons behind them are not currently transparent, and that transparency is essential no 

matter the size of the uplift or the cause.

38 ELCON cites analysis from an August 2014 

Commission Staff paper that outlined the potential benefits of additional transparency.39

Competitive Suppliers state that they strongly support the proposed transparency 

provisions, and assert that increased transparency could lead to reductions in uplift.40 

R Street Institute states that price formation visibility in energy and ancillary services 

markets is very important for efficient market functionality and comments that each of 

the Commission’s proposed requirements is reasonable.41 Exelon notes that transparency 

around uplift and the actions that cause uplift is an important step to minimizing system 

uplift costs, and that by allowing visibility into the causes, location, and frequency of 

uplift payments, market participants will have the information necessary to advocate 

effectively for improvements to the RTO/ISO operational procedures and market rules 

and, more importantly, to discover and invest in cost-saving opportunities.42 Financial 

 37 Appian Way Comments at 1, 8. 

38 ELCON Comments at 4.

39 Id. at 10 (citing FERC, Staff Analysis of Uplift in RTO and ISO Markets, Docket 

No. AD14-14, at 28 (2014), https://www.ferc.gov/legal/staff-reports/2014/08-13-14-

uplift.pdf (Staff Analysis of Uplift)).

40 Competitive Suppliers Comments at 8.

41 R Street Institute Comments at 5-6.

42 Exelon Comments at 9.
Docket No. RM17-2-000 - 19 -

Marketers Coalition state that transparency is critical to a well-functioning organized 

market because it is the key to proper price signals.

43 

24. Several commenters express general support for the proposed transparency 

reforms, but do not comment in-depth on the need for reform.

44 Several other 

commenters acknowledge a need for reform, but are reserved in expressing support. 

APPA and NRECA state that they have long supported additional transparency in the 

RTO/ISO markets and do not oppose the proposed requirements, but they caution the 

Commission not to overstate any potential outcomes, such as incenting market 

participants to advocate for changes to operational procedures or incenting investments. 

They add, however, that there is still value in making the information available.45 MISO 

Transmission Owners state that enabling market participants to gain additional 

information regarding the causes, frequency, and costs of out-of-market actions and 

associated uplift costs will enhance market efficiency.46 But they strongly oppose 

requiring reporting of resource-specific information related to uplift payments, stating 

that such reporting would have an anti-competitive effect on the market, and would work 

 43 Financial Marketers Coalition Comments at 36-37.

44 Golden Spread Comments at 11-12; MISO Comments at 2; NYISO Comments 

at 5, 12; PJM Comments at 11; PJM Market Monitor Comments at 9; Potomac 

Economics Comments at 11, 13; SPP Market Monitor Comments at 3. 

45 APPA and NRECA Comments at 12-13.

46 MISO Transmission Owners Comments at 5.
Docket No. RM17-2-000 - 20 -

counter to the Commission’s transparency goals articulated in the NOPR.47 Potomac 

Economics states that, in general, it supports transparency. However, Potomac 

Economics asserts that immediate release of uplift information is not important for 

transparency because uplift is a settlement process.

48 Several commenters raise concerns 

about other specific elements of the proposal but do not generally oppose the proposed 

transparency requirements.

49 

25. CAISO states that it supports greater market transparency but argues that its 

existing reporting practices on uplift payments and exceptional dispatch provide 

sufficient transparency, and that additional reporting would be overly burdensome and 

problematic for CAISO.50

26. The Commission also proposed in the NOPR to require that each RTO/ISO that 

currently allocates the costs of real-time uplift to deviations allocate such real-time uplift 

costs only to those market participants whose transactions are reasonably expected to 

have caused the real-time uplift costs. Although some commenters support the proposed 

 47 Id. at 6-11.

48 Potomac Economics Comments at 11.

49 EEI Comments at 6-10; ISO-NE Comments at 42; PJM Market Monitor 

Comments at 9; SPP Comments at 4-5. 

50 CAISO Comments at 2-3.
Docket No. RM17-2-000 - 21 -

uplift allocation reforms,

51 others broadly oppose the proposed reforms.52 Still others, 

while not expressing outright opposition, raise significant concerns about whether a 

generic approach to the issue is merited, or find flaws in major elements of the uplift 

allocation proposal.

53

B. Determination

27. Based on our analysis of the record in this proceeding, we adopt the preliminary 

findings related to transparency in the NOPR and conclude that the existing RTO/ISO 

practices of reporting uplift, operator-initiated commitments, and transmission constraint 

penalty factors are insufficiently transparent, resulting in rates that are unjust and 

unreasonable. We find that the current reporting on uplift is insufficient because no 

RTO/ISO currently reports uplift on a resource-specific basis. Some RTOs/ISOs do not 

report uplift by zone, and some do not report in a machine-readable format. Additionally, 

reporting on operator-initiated commitments is insufficient because some RTOs/ISOs do 

not report the reasons for these commitments, the zones in which the commitments are 

 51 See, e.g., Appian Way Comments at 3-7; Direct Energy Comments at 1-10; 

Diversified Trading/eXion Energy Comments at 4-5; EEI Comments at 3-6; ELCON 

Comments at 5-9; Financial Marketers Coalition Comments at 17-36; Golden Spread 

Comments at 6-10; MISO Transmission Owners Comments at 5; Potomac Economics

Comments at 3-10; XO Energy Comments at 3-53; R Street Institute Comments at 2-4.

52 See, e.g., CAISO Comments at 3-10; Calpine Comments at 2-7; ISO-NE 

Comments at 4-41; PJM Comments at 2-10; PJM Market Monitor Comments at 1-9; SPP 

Comments at 2-3; SPP Market Monitor Comments at 2-3.

53 See, e.g., CAISO Market Monitor Comments at 1-10; Exelon Comments at 4-7; 

IRC Comments at 2-6; PG&E Comments at 3-6; TAPS Comments at 2-8.
Docket No. RM17-2-000 - 22 -

made, or information about the size of the system needs for which resources are 

committed. Finally, some RTOs/ISOs do not include transmission constraint penalty 

factor values in their tariffs, and most do not include practices related to the use of 

transmission constraint penalty factors in their tariffs. This Final Rule will remedy these 

deficiencies and is therefore necessary to achieve a level of transparency that will result 

in just and reasonable rates.

28. As described above, the transparency proposal received a broad level of support

from commenters. CAISO is the singular commenter to oppose the proposed 

transparency reforms outright. CAISO states that its reporting practices are sufficient and 

that the burden of additional reporting would outweigh the benefits of the proposed 

reforms. As explained below, we disagree that existing transparency practices are 

sufficient. We do, however, modify the proposed transparency requirements to reduce 

the potential burden of the reforms and to address commenters’ other concerns including 

the potential disclosure of commercially-sensitive information and the transparency value 

of consistent reporting. These modifications are discussed below in the subsections 

dealing with each requirement.

29. Based on our analysis of the record in this proceeding, we decline to adopt the 

preliminary finding related to uplift cost allocation in the NOPR. We continue to believe 

that uplift should ideally be allocated to those market participants whose transactions 

caused the uplift and that allocations of uplift costs should avoid penalizing behavior that 

can improve price formation. That said, some commenters raised substantial concerns 

about the uplift cost allocation reforms proposed in the NOPR. They expressed concern 
Docket No. RM17-2-000 - 23 -

about the application of the NOPR proposal to certain RTOs/ISOs in light of the reasons 

for uplift in these markets, and whether certain RTOs/ISOs would be able to implement 

the generic uplift cost allocation reforms proposed in the NOPR. We find those concerns 

sufficiently persuasive to decline to take generic action at this time. Accordingly, we 

withdraw the NOPR proposal to require that each RTO/ISO that currently allocates the 

costs of real-time uplift to deviations allocate such real-time uplift costs only to those 

market participants whose transactions are reasonably expected to have caused the realtime uplift costs.

IV. Transparency Reforms

30. Having concluded that the existing transparency practices result in rates that are 

not just and reasonable, section 206 of the Federal Power Act requires that the 

Commission determine the practices that will result in rates that are just and reasonable.54 

We direct each RTO/ISO to establish in its tariff the following three requirements related 

to uplift reporting and one requirement related to transmission constraint penalty factors.

31. Each RTO/ISO must post a monthly Zonal Uplift Report of all uplift, paid in 

dollars, and categorized by transmission zone, day, and uplift category. We define 

transmission zone as a geographic area that is used for the local allocation of charges, 

such as a load zone that is used to settle charges for energy. Transmission zones with 

fewer than four resources may be aggregated with one or more neighboring transmission 

zones, until each aggregated zone has at least four resources, and reported collectively. 

 54 16 U.S.C. 824e.
Docket No. RM17-2-000 - 24 -

This report must be posted in machine-readable format on a publicly-accessible portion 

of the RTO’s/ISO’s website within 20 calendar days of the end of each month.

32. Each RTO/ISO must post a monthly Resource-Specific Uplift Report containing 

the resource name and total amount of uplift paid in dollars aggregated across the month 

to each resource that received uplift payments. This report must be posted in machinereadable format on a publicly-accessible portion of the RTO’s/ISO’s website within 

90 calendar days of the end of each month.

33. Each RTO/ISO must post a monthly Operator-Initiated Commitment Report 

listing the commitment size, transmission zone, commitment reason, and commitment 

start time of each operator-initiated commitment. We define an operator-initiated 

commitment as a commitment made after the day-ahead market for a reason other than 

minimizing the total production costs of serving load. Commitment reasons shall 

include, but are not limited to, system-wide capacity, constraint management, and voltage 

support. This report must be posted in machine-readable format on a publicly accessible 

portion of the RTO’s/ISO’s website within 30 calendar days of the end of each month. 

34. Each RTO/ISO must follow the Transmission Constraint Penalty Factor 

requirements to include, in its tariff, its transmission constraint penalty factor values; the 

circumstances, if any, under which the transmission constraint penalty factors can set 

LMPs; and the procedure, if any, for temporarily changing the transmission constraint 

penalty factor values. Any procedure for temporarily changing transmission constraint 

penalty factor values must provide for notice of the change to market participants as soon 

as practicable. 
Docket No. RM17-2-000 - 25 -

35. The Zonal Uplift Report is discussed in section IV.A. The Resource-Specific 

Uplift Report is discussed in section IV.B. The Operator-Initiated Commitment Report is 

discussed in section IV.C. The Transmission Constraint Penalty Factor Requirements are 

discussed in section IV.D.

A. Zonal Uplift Report

1. NOPR Proposal

36. In the NOPR, the Commission proposed to require each RTO/ISO to post a report 

of the uplift paid in dollars and categorized by transmission zone, day, and uplift 

category. The Commission proposed to define transmission zone as the geographic area 

that is used for the local allocation of charges. The Commission proposed to allow 

transmission zones with fewer than four resources to be aggregated with a neighboring 

zone and reported collectively. The Commission further proposed to allow RTOs/ISOs 

to omit a transmission zone from reporting in a given month if it is the only zone and 

contains fewer than four resources or if, when combined with a neighboring transmission 

zone, the combined zones still have fewer than four resources. The Commission 

proposed to require that each RTO/ISO post the report on a publicly accessible portion of 

its website within 20 calendar days of the end of each month.55

37. The Commission reasoned that with more granular information on locations, 

amounts, and types of uplift, market participants would be able to better evaluate possible 

 55 NOPR, FERC Stats. & Regs, ¶ 32,721 at Regulatory Text. 
Docket No. RM17-2-000 - 26 -

solutions to reduce the incurrence of uplift.56 In proposing to allow RTOs/ISOs to 

aggregate and collectively report transmission zones with fewer than four resources and 

to exempt from reporting aggregated zones with fewer than four resources, the 

Commission sought to balance the benefits of greater transparency with concerns about 

the potential disclosure of commercially-sensitive information.

57 In proposing a 20-day 

maximum reporting lag, the Commission sought to allow RTOs/ISOs sufficient time to 

prepare uplift data for publication after completion of their settlement windows, which 

vary among RTOs/ISOs.58

38. The Commission requested comments regarding: (1) the proposed definition of 

transmission zone, including the appropriate level of geographic granularity;59 (2) the 

timeframe for releasing the report after the end of each month;60 and (3) the proposed 

requirement for a daily breakdown of uplift categories by charge code, including any 

difficulties related to such reporting and whether different categorizations would be more 

useful.61

 56 Id. P 84.

57 Id. PP 87-89.

58 Id. P 88.

59 Id. P 85.

60 Id. P 86.

61 Id. P 86.
Docket No. RM17-2-000 - 27 -

2. Comments

39. Numerous commenters support the proposed requirement for RTOs/ISOs to report 

daily uplift payments by transmission zone and uplift category.62 ELCON asserts that 

uplift payments inherently lack transparency because they are not included in market 

prices, and that increased information could promote the identification of system needs 

and facilitate investment.63 Designated Marketers state that market participants lack 

information necessary to invest in generation, transmission, or demand response that 

could prevent uplift.64 Diversified Trading/eXion Energy, Exelon, and Golden Spread all 

argue that additional information on the causes of uplift will also allow market 

participants to evaluate RTO/ISO uplift practices and raise concerns through stakeholder 

processes.65 While sympathetic to confidentiality concerns, Competitive Suppliers assert 

that each RTO/ISO can provide more information on the causes of uplift, and point to 

NYISO’s reporting practices as an example demonstrating that increased transparency 

 62 Appian Way Comments at 8; AWEA Comments at 10; Brookfield Comments 

at 2; Calpine Comments at 8; Competitive Suppliers Comments at 9; Designated 

Marketers Comments at 5; Direct Energy Comments at 10; Diversified Trading/eXion 

Energy Comments at 5; ELCON Comments at 9-10; Exelon Comments at 9; Financial 

Marketers Coalition Comments at 38; Golden Spread Comments at 11-12; PJM 

Comments at 11; PJM Market Monitor Comments at 9; R Street Institute Comments at 5; 

SPP Market Monitor Comments at 3; TAPS Comments at 8; XO Energy Replacement 

Comments at 1, 34.

63 ELCON Comments at 9.

64 Designated Marketers Comments at 5.

65 Diversified Trading/eXion Energy Comments at 5; Exelon Comments at 9; 

Golden Spread Comments at 12.
Docket No. RM17-2-000 - 28 -

can be achieved without compromising confidentiality.66 Competitive Suppliers and 

Financial Marketers Coalition assert that the proposed uplift report will ensure consistent 

disclosure of uplift information among RTOs/ISOs.67

40. Other commenters either do not support the proposed zonal uplift report 

requirement68 or state that they support the goals of improved transparency into RTO/ISO 

uplift costs but raise concerns about specific elements of the proposed report,69 as 

discussed below. 

a. Zonal Definition

41. Responding to the Commission’s request for comment on the proposed definition 

of “transmission zone” as a geographic area that is used for the local allocation of 

charges,70 several RTOs/ISOs provide descriptions of the geographic granularity of their 

current reporting. ISO-NE states that it reports uplift based on how costs are allocated: 

uplift allocated at the system level is reported on a system-wide basis; uplift allocated 

regionally is reported regionally. ISO-NE states that it also reports uplift by Reliability 

Region, which are equal to load zones used in energy settlement. ISO-NE believes it 

 66 Competitive Suppliers Comments at 9.

67 Id. at 9; Financial Marketers Coalition Comments at 38.

68 CAISO Comments at 12-13.

69 EEI Comments at 6; MISO Transmission Owners Comments at 5-6; NYISO 

Comments at 5.

70 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 85.
Docket No. RM17-2-000 - 29 -

complies with the NOPR proposal, but requests that the Commission clarify that

RTOs/ISOs may propose to report uplift costs for regions that differ from “transmission 

zone,” if appropriate.71 PJM states that it currently reports uplift by transmission zone 

and supports the proposed definition as long as it can use its current zones.72 MISO 

states that it reports uplift differently depending on the uplift category. For uplift 

incurred to manage transmission constraints, MISO reports by constraint. MISO reports 

voltage and local reliability uplift by transmission interface and MISO region (i.e., North, 

South, and Central). MISO argues that a lesser degree of geographic granularity is 

appropriate to mask “transmission zones” with few market participants. MISO states that 

it supports the proposed definition.73 NYISO notes that it allocates uplift by 

Transmission District subzones.74 

42. Other commenters generally differ on the level of geographic granularity that 

should be reported. MISO Transmission Owners state that the proposed definition of 

“transmission zone” is unclear and could be susceptible to multiple interpretations. 

MISO Transmission Owners assert that the Commission should direct each RTO/ISO to 

 71 ISO-NE Comments at 42-43.

72 PJM Comments at 11.

73 MISO Comments at 11-12.

74 NYISO Comments at 6. NYISO explains that “subzones” are identified by 

investor-owned transmission owner service territories within each load zone, which can 

span more than one load zone.
Docket No. RM17-2-000 - 30 -

develop a definition of transmission zone through its stakeholder process that considers 

regional needs and ensures that all zones are large enough to ensure that resource-specific 

uplift payments cannot be calculated based on daily uplift payment reports.75 Several 

commenters argue for more granular reporting.76 R Street Institute states that uplift 

reporting at the sub-zonal level would be useful because causes can vary within a zone, 

particularly with respect to transmission congestion, but notes that more granular 

reporting may lead to confidentiality concerns and opportunities for collusion.77 

XO Energy argues that the uplift data should be as granular as possible and that

aggregation into large regions is not as useful.78 Competitive Suppliers assert that the 

Commission’s proposed reporting by transmission zone should allay any confidentiality 

concerns.79

43. Commenters also differ on the proposal to allow RTOs/ISOs to aggregate and 

collectively report uplift in transmission zones with fewer than four resources.80 NYISO 

supports the Commission’s proposal to allow RTOs/ISOs to aggregate zones because the 

 75 MISO Transmission Owners Comments at 11-12.

76 Financial Marketers Coalition Comments at 39; R Street Institute Comments at 

5; XO Energy Replacement Comments at 34.

77 R Street Institute Comments at 5.

78 XO Energy Replacement Comments at 34.

79 Competitive Suppliers Comments at 9.

80 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 89.
Docket No. RM17-2-000 - 31 -

reporting of daily uplift payments by zone could, under some circumstances, allow 

competitors to deduce a resource’s operating costs and gain a competitive advantage. 

However, NYISO seeks clarification on whether the rule references the total number of 

resources in the zone or the total number of resources in the zone that receive uplift 

payments in a given day.81 MISO Transmission Owners and NYISO argue that the 

aggregation should be based on the number of resources receiving uplift in order to 

protect confidentiality and avoid anti-competitive behavior concerns.82 MISO 

Transmission Owners also note that the Commission did not explain why four is the 

appropriate number of resources on which to base the aggregation.83 PJM and the PJM 

Market Monitor oppose the proposal to aggregate zones with fewer than four resources 

because the number of resources in a zone that receive uplift could change from month to 

month, resulting in inconsistent reporting, increased complexity, and decreased 

transparency.84 PJM asserts that its current practice of reporting by zone, even if only 

one resource in a zone receives uplift, provides sufficient transparency while protecting 

market sensitive information.85 EEI seeks clarification as to whether, for aggregation 

 81 NYISO Comments at 6-7.

82 MISO Transmission Owners Comments at 12; NYISO Comments at 7.

83 MISO Transmission Owners Comments at 12.

84 PJM Comments at 12; PJM Market Monitor Comments at 9-10.

85 PJM Comments at 12.
Docket No. RM17-2-000 - 32 -

purposes, a resource is defined as an individual unit within a plant or the entire plant, 

noting that the former definition may not provide sufficient confidentiality under certain 

circumstances.86

b. Categories

44. As noted above, numerous commenters provide general support for the proposed 

zonal uplift report, including the proposed requirement to report by uplift category. 

Three RTOs/ISOs state that they already report uplift by category. NYISO states that it 

reports uplift cost on a monthly basis by uplift cost category in its Operations 

Performance Metrics Monthly Reports.87 MISO states that its Revenue Sufficiency 

Guarantee Report already breaks out uplift payment by category, which includes certain 

charge types as long as any market participant specific data is not apparent. MISO 

requests that the Commission consider the risks of unmasking aggregate data when 

contemplating a final rule requiring a daily breakdown of uplift categories by charge 

code.88 ISO-NE states that its existing reports break out costs for its established uplift 

categories and therefore believes that it would comply with this provision.89 PJM seeks 

clarification on the definition of charge code. PJM states that it currently indicates 

 86 EEI Comments at 8.

87 NYISO Comments at 6.

88 MISO Comments at 11.

89 ISO-NE Comments at 42.
Docket No. RM17-2-000 - 33 -

market participants’ uplift charges by billing line item, and that if this is what the 

Commission means by “charge code,” it does not object to continuing this practice.90 

Brookfield states that uplift categories based on the cause for committing units out-ofmerit would help identify market reforms to reduce the need for uplift payments.91 

XO Energy asserts that aggregating data into large categories reduces its usefulness.92

c. Timing and Burden

45. Several RTOs/ISOs discuss their existing uplift reporting practices and timing, as 

well as the level of additional burden that would be required to meet the proposed 

requirements. ISO-NE states that its existing reports appear to satisfy most of the 

proposed requirements and that implementation of any new requirements should be 

relatively simple. ISO-NE believes that 20 days is sufficient time for monthly uplift 

reporting.93 NYISO states that while it already reports uplift costs by category on a 

monthly basis, it would need to revise its processes for developing and posting its report, 

including posting in a machine-readable format.94 MISO states that its daily uplift report

that is posted eight days after the operating day and broken out by hour, category, and 

transmission constraint provides sufficient information on areas that need transmission 

 90 PJM Comments at 12.

91 Brookfield Comments at 2.

92 XO Energy Replacement Comments at 34.

93 ISO-NE Comments at 43.

94 NYISO Comments at 5-6.
Docket No. RM17-2-000 - 34 -

upgrades and supply resources.

95 PJM states that its current uplift reports provide more 

details, such as totals by type of uplift credit, than those proposed by the Commission and 

are posted within seven business days of the end of each month. PJM consequently 

requests, and Calpine concurs, that it may continue to post the additional details and that 

the proposed timeline be a minimum standard.96 CAISO states that it already provides 

significant transparency on uplift payments on a monthly basis. CAISO argues that the 

proposed requirements would be costly to implement and could interfere with other 

initiatives. CAISO further asserts that the proposed requirement to post uplift payment 

data within 20 days of the end of the month is unreasonable, given CAISO’s existing 

reporting requirements and the verification necessary to ensure accurate reporting. 

CAISO requests that, if the Commission were to impose these reporting requirements, it 

be allowed to include the requested information in the monthly reports it already 

produces and posts at the end of the month following the month of reported data.97 

46. XO Energy responds to several of CAISO’s arguments. It notes that CAISO’s 

current uplift reports contain only charts, with no mechanism to extract the raw data.98 

XO Energy generally asserts that uplift should be reported at the same time it is settled 

 95 MISO Comments at 11.

96 Calpine Comments at 8; PJM Comments at 13.

97 CAISO Comments at 12-13.

98 XO Energy Reply Comments at A-2.
Docket No. RM17-2-000 - 35 -

and specifically points out that CAISO settles uplift three days after the operating day, 

and therefore should be able to post the uplift data within 20 days of the end of the 

month.99 XO Energy suggests that if the proposed detailed reports are too timeconsuming to produce quickly, RTOs/ISOs should post a simple spreadsheet on their 

website while their systems are being updated.100 

d. Other Issues

47. Direct Energy requests that the Commission clarify that the transparency 

provisions apply to all uplift costs, not just those resulting in allocations to deviations 

from day-ahead schedules.101 

48. EEI and MISO Transmission Owners assert that the proposed report would 

primarily benefit market participants, so in order to protect market participants’ 

confidentiality, the information should be posted on a password-protected portion of an 

RTO’s/ISO’s website, rather than made publicly available.102 Designated Marketers, on 

the other hand, support the proposed requirement that RTOs/ISOs post the uplift 

information in a machine-readable format on an accessible portion of the RTO/ISO 

website. Designated Marketers argue that information that is not machine-readable can 

 99 XO Energy Replacement Comments at 34; XO Energy Reply Comments at A-3. 

100 XO Energy Replacement Comments at 34.

101 Direct Energy Comments at 10.

102 EEI Comments at 7; MISO Transmission Owners Comments at 13.
Docket No. RM17-2-000 - 36 -

reduce transparency by inhibiting data processing and may disadvantage those that do not

have access to electronic versions of the data through other channels.103

49. Exelon suggests that, in addition to the proposed reporting requirements, the 

Commission also require RTOs/ISOs to submit a one-time report covering the years 2012 

through 2016 that identifies uplift categories and provide the aggregate uplift cost 

associated with each category.104

3. Determination

50. We adopt the proposal that each RTO/ISO report, in the Zonal Uplift Report, the 

total daily uplift payments in dollars in each category paid to the resources in each 

transmission zone, subject to modifications and clarifications discussed below. We find 

that current RTO/ISO practices do not provide sufficient transparency regarding uplift 

payments. Because uplift payments are not included in publicly available market prices, 

they inherently lack transparency and must be reported separately to show the cost of 

serving load and maintaining a reliable electric system. As stated in the NOPR, access to 

information on uplift payments may allow market participants to evaluate possible 

solutions to reduce the incurrence of uplift.105 We find that the basis for this requirement,

as outlined in the NOPR, remains compelling. The Zonal Uplift Report will provide 

granular information about the location, timing, and causes of uplift. Such information

 103 Designated Marketers Comments at 8.

104 Exelon Comments at 9-10.

105 NOPR, FERC Stats. & Regs. ¶ 32,721 at PP 78, 84.
Docket No. RM17-2-000 - 37 -

will facilitate more informed stakeholder discussions that support planning processes,

improve the ability of market participants to raise concerns with RTO/ISO uplift 

payments, and support cost-effective solutions to system needs by allowing market 

participants to make more informed investment decisions. Over the long term, improved 

RTO/ISO practices and additional investment may lead to reduced uplift payments and 

increased market efficiency. PJM’s recent report summarizing market outcomes during 

the December 28, 2017–January 7, 2018 cold snap provides an example of timely 

reporting of uplift cost information. PJM’s report identifies uplift cost by category, by 

day, and by resource type, identifying the days when specific uplift categories were 

greatest.106 PJM uses these data to suggest potential areas for improvement. We note 

that the report was issued February 26, 2018, less than two months after the end of the 

cold weather events. The uplift data provided in the report, which is consistent with the 

data required in this Final Rule, illustrates the type of information that market participants 

and interested stakeholders could use to understand how RTO/ISO markets operate 

during stressful system conditions and provide a basis for a stakeholder discussion about 

potential market reforms. The requirements of this Final Rule will ensure that market 

participants have access to uplift information in a consistent format on an ongoing basis.

51. We address commenters’ concerns regarding the Zonal Uplift Report below. 

 106 PJM, PJM Cold Snap Performance, Dec. 28, 2017 to Jan. 7, 2018, 27-30 

(Feb. 26, 2018), http://www.pjm.com/-/media/library/reports-notices/weatherrelated/20180226-january-2018-cold-weather-event-report.ashx (PJM Cold Snap 

Performance Report). 
Docket No. RM17-2-000 - 38 -

52. We adopt the definition proposed in the NOPR of “transmission zone” as a 

geographic area that is used for the local allocation of charges, such as a load zone that is 

used to settle charges for energy. We find that this level of geographic reporting will 

improve transparency by providing more specific information about the location of 

system needs. For instance, understanding that a particular category of uplift is 

concentrated in a limited area could provide information about the nature of the reliability 

need or could inform discussions about uplift cost allocation. 

53. Some commenters argue that RTOs/ISOs should be permitted to define 

transmission zones more broadly because daily uplift payments in combination with other 

public information could be used to derive a resource’s energy offer or cost information, 

which some characterize as confidential because it is commercially sensitive. 

Commenters assert that the revelation of cost or offer data could lead to collusion or 

gaming. We recognize that it may be possible, under specific circumstances, to deduce 

an individual resource’s daily uplift payments by using the information provided in the 

Zonal Uplift Report and Resource-Specific Uplift Report. For instance, if the ResourceSpecific Uplift Report makes clear that only one resource within a zone has received 

uplift during a given month, and if that resource has only one generating unit, then the 

Zonal Uplift Report would reveal the resource’s daily uplift payments. This information

could be used with knowledge of the resource’s output and publicly-available data on 
Docket No. RM17-2-000 - 39 -

LMPs to estimate the resource’s energy offer or cost.107 We understand commenters’ 

concern to be that if a resource’s offer or costs are revealed, another resource owner 

could increase its own offer above its costs in a manner that would be inconsistent with a 

competitive market. 

54. Out of an abundance of caution and as discussed below, we delay the timing of 

Resource-Specific Uplift report to allow a 90-day time lag in releasing the ResourceSpecific Uplift Report108 to reduce the likelihood that the information could be used to

harm competition or individual market participants. We also point out that additional 

transparency may deter collusion and gaming and provide a means for anti-competitive 

behavior to be identified and addressed more quickly. As commenters suggest, market 

participants may use the information provided by the reports to call attention to potential 

market issues.

55. In the NOPR, we recognized that RTOs/ISOs may have very small transmission 

zones, and sought to balance the benefits of greater transparency with concerns about 

revealing daily resource-specific uplift information by (1) allowing RTOs/ISOs to 

aggregate any transmission zone containing fewer than four resources with a neighboring 

 107 We note that such estimates may be imprecise, as they would likely rely on 

additional assumptions such as the relative values of the start-up, no-load or minimum 

load, and incremental energy components of the resource’s offer. 

108 In the NOPR, we proposed to require a 20-day lag for both uplift reports. As 

discussed below, we modify the lag to 90 days for the Resource-Specific Uplift Report.
Docket No. RM17-2-000 - 40 -

zone and report them collectively, and (2) exempting from reporting any combined 

transmission zone with fewer than four resources. 

56. In response to comments, we clarify that any aggregation should be based on the 

number of resources located in the zone rather than the number of resources in the zone

that receive uplift payments in a given reporting period. As noted by PJM and the PJM 

Market Monitor, aggregating based on the number of resources that receive uplift 

payments could lead to different zonal aggregations from month to month and 

inconsistent zonal reporting, which would add complexity and reduce transparency.

109 

Aggregation based on the number of resources located in a zone will ensure a consistent 

zonal definition from month-to-month, which we would only expect to change with the 

addition or retirement of resources. We find that aggregating transmission zones to 

achieve a minimum of four resources addresses concerns that individual resource uplift 

payments could be deduced from the report. We reason that if a zone has at least 

four resources, there will be enough possibilities of which resource or resources received 

uplift that it will be unlikely that the Zonal Uplift Report alone will reveal individual 

resources’ uplift payments. 

57. We also clarify that, for the purpose of zonal aggregation, the term “resource”

refers to an entire generating facility and not each individual unit within a plant. We 

agree with EEI that if a transmission zone contained, for example, a single power plant 

 109 PJM Comments at 12; PJM Market Monitor Comments at 10.
Docket No. RM17-2-000 - 41 -

with four units, aggregation with a neighboring zone would be necessary to avoid the 

possibility that the zonal uplift report alone could reveal the plant’s daily uplift payments.

58. We also modify the permissible level of aggregation. The proposal in the NOPR 

to allow a transmission zone with fewer than four resources to be aggregated with a 

single neighboring zone and to exempt from the reporting requirement any aggregated

zone that still contains fewer than four resources could result in a zone that is 

permanently exempted from reporting, in light of the clarification above. Instead, we will 

allow RTOs/ISOs to aggregate transmission zones containing fewer than four resources 

with one or more neighboring zones in such a manner that all aggregated zones have at 

least four resources. Allowing such aggregation obviates the need for any aggregated 

zone to be exempted from the reporting requirement. This modification preserves the 

intended protections of the aggregation proposed in the NOPR while closing a potential 

reporting gap.

59. On balance, our definition of transmission zone and the associated aggregation 

protections provide the transparency benefits of geographically granular uplift 

information while minimizing the risk of harm to the market from the potential disclosure 

of commercially-sensitive information. However, we acknowledge that RTOs/ISOs may 

have multiple existing types of zones that could meet our definition. On compliance, we 

require each RTO/ISO to include in its tariff the type of zone that it proposes to use in its 

Zonal Uplift Report and explain how the chosen type of zone meets the definition of

transmission zone adopted in this Final Rule, as well as explain any proposal to aggregate 

transmission zones that fits the characteristics described above. While our definition of 
Docket No. RM17-2-000 - 42 -

transmission zone provides RTOs/ISOs a level of flexibility, we note that transmission 

zones are defined as areas that are used for the local allocation of charges; therefore, we 

expect each RTO/ISO to propose transmission zones that provide an appropriate level of 

geographic granularity. 

60. We adopt the NOPR proposal to require the reporting of zonal uplift by category. 

As noted above, numerous commenters express support for this proposal, and several 

RTOs/ISOs already report such information. Reporting the causes of uplift in each 

transmission zone on each day will help market participants understand the relationship 

between system conditions, location, and reasons that uplift is incurred. Market 

participants will therefore be better equipped to raise concerns about RTO/ISO uplift 

payments and direct appropriate infrastructure investment to reduce the need for a given 

type of uplift payment. No commenters opposed including categories in the Zonal Uplift 

Report. As mentioned in the NOPR, we expect the categories to be based on the 

RTO/ISO uplift charge codes. 110 For RTOs/ISOs that do not use the term “charge 

codes,” we clarify that “charge codes” refers to individual charges for settlement 

purposes. We expect that basing uplift categories on existing charge codes will ease the 

potential reporting burden on RTOs/ISOs. 

61. With respect to timeliness of reporting, we adopt the NOPR proposal to require 

that each RTO/ISO post this Zonal Uplift Report within 20 calendar days of the end of 

the month. However, in response to CAISO’s concern on this issue, on compliance we

 110 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 86.
Docket No. RM17-2-000 - 43 -

will consider proposals with longer timelines if an RTO/ISO demonstrates that the 20-day 

deadline does not provide an RTO/ISO with sufficient time to compile the report given its 

existing uplift settlement and reporting timelines. 

62. Regarding other issues raised by commenters with respect to this report, in 

response to Direct Energy we confirm that RTOs/ISOs must report all uplift payments to 

resources and not just those resulting from deviations from day-ahead schedules in both 

the Zonal Uplift Report and the Resource-Specific Uplift Report. We also confirm that 

RTOs/ISOs may choose to report more information and/or to report more promptly. We 

adopt the NOPR proposal to require each RTO/ISO to publish the two uplift reports, the 

Zonal Uplift Report and the Resource-Specific Uplift Report, in a machine-readable 

format on a publicly accessible, rather than password-protected, portion of its website. 

As discussed above, we are not persuaded that the potential revelation of a resource’s

uplift payments, subject to the discussed protections, would result in harm to competition 

or to market participants. Moreover, while we have discussed the benefits in the context 

of existing market participants, we find that other stakeholders such as third-party 

researchers, potential future market participants, and ratepayers may also benefit from 

public availability of this data. Finally, while we recognize the potential transparency 

benefits of the historical uplift report requested by Exelon, we find that it goes beyond the 

scope of this rulemaking and decline to require it here. 
Docket No. RM17-2-000 - 44 -

B. Resource-Specific Uplift Report

1. NOPR Proposal

63. In the NOPR, the Commission proposed to require each RTO/ISO to post a 

monthly report containing the resource name and total amount of uplift paid in dollars 

aggregated across the month to each resource that received uplift payments. The 

Commission proposed to require that the report be posted on a publicly-accessible portion 

of each RTO’s/ISO’s website within 20 calendar days of the end of each month.

111

64. The Commission reasoned that with more granular information on the location and 

amounts of uplift, market participants may be able to better evaluate possible solutions to 

reduce the incurrence of uplift. 112 The Commission sought to mask daily uplift payments 

by requiring that resource-specific uplift payment data be aggregated across the month.

113 

65. The Commission requested comments on: (1) whether these resource-specific 

reports should also be broken out by uplift category, be reported using a different time 

duration, or contain other additional details;

114 and (2) whether 20 calendar days after the 

end of the month was a reasonable timeframe for releasing the information.

115 

 111 Id. at Regulatory Text.

112 Id. P 84.

113 Id. P 89.

114 Id. P 83.

115 Id. P 86.
Docket No. RM17-2-000 - 45 -

2. Comments

66. Many commenters generally support116 or state that they are not opposed117 to the 

NOPR proposal for a resource-specific monthly report. Appian Way notes that some 

RTOs/ISOs have indicated that most uplift costs are attributed to a few units, and that the 

Commission’s Office of Enforcement has brought cases alleging inflated uplift costs for 

certain units. Appian Way believes that improved transparency into which units receive 

uplift would allow market participants to advocate for solutions and call attention to these 

issues more quickly and efficiently.118 Golden Spread similarly argues that the more 

information that is available to all market participants, and not just market operators, the 

faster market imperfections can be removed.119 Brookfield and Exelon state that more 

granular and comprehensive data would help market participants identify and address 

root causes of uplift.120 Financial Marketers Coalition agree that if details on uplift 

payments are not presented, it is unlikely uplift drivers will be identified and displaced 

 116 Appian Way Comments at 8; AWEA Comments at 10; Brookfield Comments 

at 2; Calpine Comments at 8; Designated Marketers Comments at 5-6; Direct Energy 

Comments at 10; Diversified Trading/eXion Energy Comments at 5; Exelon Comments 

at 9; Financial Marketers Coalition Comments at 39; Golden Spread Comments at 11-12; 

NYISO Comments at 5; PJM Market Monitor Comments at 10; R Street Institute 

Comments at 5; TAPS Comments at 8; XO Energy Replacement Comments at 34. 

117 ISO-NE Comments at 43; PJM Comments at 11.

118 Appian Way Comments at 8.

119 Golden Spread Comments at 12.

120 Brookfield Comments at 2; Exelon Comments at 9.
Docket No. RM17-2-000 - 46 -

through competition.

121 Similarly, XO Energy agrees that the usefulness of data will be 

reduced if it is aggregated.122 

67. On the other hand, MISO and MISO Transmission Owners assert that the benefits 

of the resource-specific report are unclear. MISO Transmission Owners state the 

Commission does not explain why resource-level information is necessary and why the 

other transparency reforms are insufficient to meet the Commission’s goals. Moreover, 

they contend market participants do not need to know resource-level information to 

understand RTO/ISO actions and react properly to them.123 MISO Transmission Owners 

point out that market monitors can use confidential data to propose fixes for market 

design flaws.124 MISO similarly asserts that it is unnecessary to disclose resourcespecific uplift information beyond its current processes. MISO and MISO Transmission 

Owners assert that the value of publicly disclosed information may be outweighed by its

risk of harm to the markets.

125 MISO Transmission Owners argue that continuing to 

require public utilities to report uplift payments in EQR while also implementing this 

proposal would provide no additional benefit and would be duplicative.126

 121 Financial Marketers Coalition Comments at 38.

122 XO Energy Replacement Comments at 34.

123 MISO Transmission Owners Comments at 7-8.

124 Id. at 9-10.

125 MISO Comments at 12-13; MISO Transmission Owners Comments at 8-9.

126 MISO Transmission Owners Comments at 11. 
Docket No. RM17-2-000 - 47 -

a. Confidentiality 

68. Some commenters highlight concerns around confidentiality and the release of 

data in a resource-specific monthly report. MISO Transmission Owners and Potomac 

Economics raise the concern that a resource-specific report could allow the discovery of a 

resource’s sensitive cost information or lead to some form of collusion among 

suppliers.

127 MISO Transmission Owners argue there may be instances when market 

participants and competitors could derive sensitive resource cost information by 

combining resource-specific uplift with settlement LMPs and backing out costs.128 

MISO Transmission Owners and EEI argue that monthly aggregation may not 

sufficiently mask daily uplift payments if a unit is infrequently paid uplift or committed 

out-of-market within a month.129 MISO echoes this concern, arguing that the 

Commission should consider the effect of resource energy offers, which may be used for 

anti-competitive purposes such as gaming.130 Potomac Economics argues that releasing 

uplift payment information with only a minimal lag could allow for tacit or explicit 

collusion among suppliers.131 MISO and SPP state that resources’ uplift information is 

 127 Id. at 6-7; Potomac Economics Comments at 11.

128 MISO Transmission Owners Comments at 6-7.

129 EEI Comments at 8; MISO Transmission Owners Comments at 7.

130 MISO Comments at 13; PJM Comments at 11.

131 Potomac Economics Comments at 11.
Docket No. RM17-2-000 - 48 -

considered confidential in their regions.

132 PJM does not oppose the NOPR proposal, but 

notes stakeholder concerns that resource-specific uplift reporting could reveal marketsensitive information such as bidding strategies.133 The SPP Market Monitor contends 

that identifiable information for resources should not be released.134 

69. Several commenters provide suggestions for protecting resources’ confidential 

information. EEI and MISO Transmission Owners argue that because the Commission 

has only identified benefits for market participants, the resource-specific uplift 

information should be available only to market participants.

135 Moreover, they argue the 

data should be posted to a password-protected portion of the RTO’s/ISO’s website.136 

MISO Transmission Owners further state that the data should only be accessible to those 

market participants that have shown a need to access the information and have signed a 

confidentiality agreement.137 Competitive Suppliers state that uplift information should 

be reported on a MW basis rather than a unit-specific basis.138 EEI suggests that the 

 132 MISO Comments at 13; SPP Comments at 3 (citing Attachment AE, 

Section 11).

133 PJM Comments at 11.

134 SPP Market Monitor Comments at 3.

135 EEI Comments at 7; MISO Transmission Owners at 13. 

136 EEI Comments at 7; MISO Transmission Owners Comments at 13.

137 MISO Transmission Owners Comments at 13.

138 Competitive Suppliers Comments at 9.
Docket No. RM17-2-000 - 49 -

Commission allow RTOs/ISOs to determine the level of transparency needed to protect 

commercially sensitive information.139

70. MISO Transmission Owners, EEI, and Potomac Economics all comment that if a 

resource-specific report is adopted, a final rule should increase the lag time for releasing 

the report or should aggregate the data over a longer time period. Potomac Economics 

asserts that an immediate release of uplift information does not improve transparency 

because uplift is a settlement process and market participants cannot take economic 

actions to reduce uplift costs. Potomac Economics also believes the proposed 20-day lag 

is too short to ensure competition will not be adversely affected and recommends at least 

a three-month lag, which it asserts will not diminish the transparency value of the 

report.

140 MISO Transmission Owners agree that three months is the appropriate lag for 

reporting any resource-specific report on uplift payments, noting that this reporting 

timing has been in effect for some time for EQR.141 EEI suggests that uplift information 

be aggregated over the quarter and reported quarterly, in order to lessen the ability of 

market participants to deduce resources’ offers while providing an appropriate level of

transparency.142 

 139 EEI Comments at 8-9.

140 Potomac Economics Comments at 11.

141 MISO Transmission Owners Comments at 10-11.

142 EEI Comments at 8.
Docket No. RM17-2-000 - 50 -

71. Multiple commenters argue that the proposed monthly aggregation for reporting is 

sufficient to reduce data and resource confidentiality concerns. R Street Institute finds 

that monthly aggregation is reasonable and provides sufficient masking of daily offer 

behavior.143 TAPS agrees that the proposal strikes the appropriate balance of increasing 

transparency against confidentiality and competition concerns.144 In response to 

confidentiality concerns, XO Energy notes that resource-specific uplift information is 

already publicly reported in EQR.145 Financial Marketers Coalition states that 

RTOs/ISOs should be able to mask, rather than withhold from the market, particularly 

sensitive information such as bid data, but asserts that uplift payments are not a 

competitive aspect of the market and should be made clear to market participants.

146 

ELCON and EEI recommend allowing RTOs/ISOs flexibility to determine the 

appropriate balance between transparency and protecting sensitive information.

147 

b. Categories and Additional Information

72. Several commenters responded to the Commission’s request for comment on 

whether the resource-specific reports should be broken out by uplift category or contain 

 143 R Street Institute Comments at 5.

144 TAPS Comments at 8.

145 XO Energy Reply Comments at A-6, A-9.

146 Financial Marketers Coalition Comments at 38.

147 ELCON Comments at 10; EEI Comments at 9.
Docket No. RM17-2-000 - 51 -

other additional details.

148 The PJM Market Monitor supports specifying the category of 

uplift but does not agree that disclosing additional information beyond categories is 

necessary.

149 Direct Energy encourages requiring RTOs/ISOs to report additional 

information for each instance when uplift costs are incurred: the name of the unit 

receiving uplift; uplift category; timeframe of the binding constraint driving the uplift 

payment; timeframe of uplift earned; operating parameter creating the need for uplift; and 

total payment to the unit.150 ISO-NE asserts that, for security reasons, public reporting of

voltage-related uplift payments on a resource-specific basis should not be required.

151 

c. Other Comments

73. As discussed in more detail with respect to the zonal uplift report, CAISO argues 

that it already posts significant information on uplift payments monthly and contends the 

proposed reports and 20-day deadline would impose significant costs on CAISO. CAISO 

requests that the Commission allow CAISO to include any required additional uplift 

information in the monthly reports it already produces.152 Conversely, ISO-NE states 

that reporting uplift payments on a resource-specific level should be simple to 

 148 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 83.

149 PJM Market Monitor Comments at 10.

150 Direct Energy Comments at 10-11.

151 ISO-NE Comments at 43.

152 CAISO Comments at 12.
Docket No. RM17-2-000 - 52 -

implement.153

3. Determination

74. We adopt the NOPR proposal and require each RTO/ISO to report the resource 

name and the total amount of uplift paid in dollars to each resource that received uplift 

payments within the calendar month. We find that this Resource-Specific Uplift Report 

provides additional transparency benefits beyond those provided by the Zonal Uplift 

Report and existing uplift reporting requirements. Below, we discuss the benefits 

particular to this report and also address commenters’ other concerns. 

75. We find that the Resource-Specific Uplift Report will improve transparency into

the causes of uplift. The Resource-Specific Uplift Report will complement the Zonal 

Uplift Report by providing more granular technology-type and geographic information, 

allowing market participants to identify potential system needs at specific locations that 

may not otherwise be revealed through price signals. The locational granularity of the 

required uplift report also mirrors the locational granularity of energy prices. We find 

that the two uplift reports in combination can improve market efficiency by providing 

information to market participants considering, for example, where to site new resources, 

transmission facilities, or demand response. In addition, as Appian Way notes, several 

RTOs/ISOs have previously indicated that uplift payments are concentrated and 

persistent among a few units, an observation corroborated by the Staff Analysis of 

 153 ISO-NE Comments at 43.
Docket No. RM17-2-000 - 53 -

Uplift.

154 As noted above, PJM’s recent Cold Snap Performance Report illustrates the 

value of resource-specific uplift information. For instance, knowing that uplift was 

concentrated in combustion turbines rather than steam units155 can provide insight

regarding the nature of the system need that is being addressed through actions that lead 

to uplift. While MISO Transmission Owners argue that market monitors have access to 

resource-specific uplift data and are therefore already able to raise any issues, other

commenters assert that disseminating resource-specific uplift information publicly would 

also allow market participants to call attention to such issues. We agree with the latter 

argument, as market participants, particularly those that may be allocated uplift costs, 

may be financially incentivized to advocate for solutions that reduce uplift costs. Market 

participants can also use this information to make investment decisions; this is something 

market monitors cannot do. Public release of this information may therefore result in 

faster or more efficient resolution to circumstances responsible for uplift which will help 

achieve just and reasonable rates. 

76. MISO Transmission Owners argue that the Resource-Specific Uplift Report is 

duplicative with the requirement that public utilities report uplift payments in EQR. EQR

serves as a reporting mechanism for public utilities to fulfill their responsibility under

section 205(c) of the Federal Power Act to have their rates and charges on file in a 

 154 Staff Analysis of Uplift at 7-10. 

155 PJM Cold Snap Performance Report at 30.
Docket No. RM17-2-000 - 54 -

convenient form and place.156 While EQR facilitates price transparency, the Commission 

has not required uplift to be reported at the level of granularity necessary to meet the

price formation objectives of this proceeding. Depending on the granularity of the 

information reported by the filer, and whether the filer reports its EQR as a single 

resource, resource level uplift information is sometimes reported in EQR. The ResourceSpecific Uplift Report would include information about specific resources, which is not 

currently required by EQR. For instance, the Staff Analysis of Uplift shows that EQR 

data contain lower total uplift payments and fewer locations reported than do non-public 

RTO/ISO uplift data.

157 Therefore, we find that the Resource-Specific Uplift Report is 

not duplicative and provides additional transparency benefits that could not be fully 

achieved under existing EQR filing requirements. 

77. Several commenters continue to express concern that the Resource-Specific Uplift 

Report could, in conjunction with other information, unintentionally reveal a resource’s 

daily uplift payments, energy offer, or cost information, which some characterize as 

confidential because it is commercially sensitive. As noted above, it may be possible, 

under specific circumstances, for a market participant to estimate a resource’s energy 

offer using the Resource-Specific Uplift Report in conjunction with the Zonal Uplift 

Report, and other information and assumptions. Commenters assert that the revelation of 

 156 16 U.S.C. 824d(c).

157 Some entities, including certain cooperatives and municipalities, were not 

required to file EQRs during the majority of the time analyzed within the report. See 

Staff Analysis of Uplift at 22.
Docket No. RM17-2-000 - 55 -

cost or offer data could lead to collusion or gaming. 

78. Out of an abundance of caution, we address these concerns regarding revealing 

commercially-sensitive information by modifying the NOPR proposal to extend the 

deadline for the release of the Resource-Specific Uplift Report from 20 to 90 calendar 

days following the end of the reporting month, as several commenters recommend. An 

RTO/ISO can propose more timely reporting on compliance to the extent it believes that 

reporting more timely does not present the kinds of risks discussed above, for instance, 

because there are consistently enough resources awarded uplift in each zone that the 

uplift reports taken together cannot be used to infer a resource’s costs. 

79. We also find that any inferred information regarding a resource’s offers or costs 

becomes less likely to be used to harm competition or individual market participants with 

the passage of time, because fuel prices and other market conditions change. After 

90 calendar days following the end of the reporting month, the report will be released in a 

different season from the incurrence of uplift, increasing the likelihood that transient 

issues will be resolved, and thus decreasing the likelihood that any deduced resourcespecific cost or offer data can be used to harm to competition or individual market

participants. Furthermore, as Appian Way suggests, transparency into resource-specific 

uplift payments can highlight potential instances of gaming and collusion for other 

market participants, and allow them to advocate for solutions and call attention to such 

issues more quickly and efficiently. Finally, some information about resource-specific 

uplift payments is already available or can be derived from EQR. 

80. We find that monthly aggregation of uplift payments to each resource, combined 
Docket No. RM17-2-000 - 56 -

with a reporting delay of 90 calendar days, strikes an appropriate balance between the 

goal of providing public information that is detailed enough to identify system needs and 

issues with RTO/ISO uplift payment practices while also preserving a reasonable level of 

protection of potentially commercially-sensitive information. We expect that the later 

deadline should also alleviate CAISO’s concern with respect to the burden of releasing 

this report on time. 

81. As with the Zonal Uplift Report, the Commission does not agree with 

commenters that argue that access to the Resource-Specific Uplift Report should be 

limited to certain market participants on a password-protected portion of the RTO/ISO 

website. Providing data only to certain market participants does not achieve the goals of

this Final Rule. As stated earlier, we find that reporting resource-specific uplift cost 

information more broadly may benefit a range of stakeholders, and we require each

RTO/ISO to publish the Resource-Specific Uplift Report in a machine-readable format 

on a publicly accessible portion of its website.

82. In the NOPR, the Commission requested comment regarding whether the 

Resource-Specific Uplift Report should include uplift categories or other additional 

details. While, as some commenters suggest, there may be additional value in reporting 

uplift categories on a resource-specific basis, we do not require RTOs/ISOs to report 

resource-specific uplift by category. We find that the requirement for RTOs/ISOs to 

report uplift categories in the Zonal Uplift Report provides sufficient transparency about 

the locations where specific types of uplift are incurred to address system needs.

However, RTOs/ISOs may choose to include uplift categories or other information in the 
Docket No. RM17-2-000 - 57 -

Resource-Specific Uplift Report, and must indicate on compliance whether they plan to 

do so.

C. Operator-Initiated Commitments

1. NOPR Proposal

83. In the NOPR, the Commission proposed to require each RTO/ISO to post 

operator-initiated commitments in MWs, categorized by transmission zone and

commitment reason, to a publicly accessible portion of its website within four hours of 

the commitment. The Commission proposed to define transmission zone as a geographic 

area that is used for the local allocation of charges.

158

84. The Commission reasoned that transparency into operator-initiated commitments 

is necessary as such commitments can affect energy and ancillary service prices and can 

result in uplift. In addition, the Commission preliminarily found that greater transparency 

would allow stakeholders to better assess the RTO’s/ISO’s operator-initiated 

commitment practices and raise any issues of concern through the stakeholder process.159

85. In the NOPR, the Commission defined an operator-initiated commitment as a 

commitment that is not associated with a resource clearing the day-ahead or real-time 

market on the basis of economics and that is not self-scheduled. The Commission added 

that this definition would include both manual and automated commitments made after 

the execution of the day-ahead market and outside of the real-time market. The 

 158 NOPR, FERC Stats. & Regs. ¶ 32,721 at Regulatory Text.

159 Id. P 92.
Docket No. RM17-2-000 - 58 -

Commission noted that the definition includes commitments made through residual unit 

commitment and look-ahead commitment processes, and manual commitments made in 

real-time. The Commission proposed that both manual and automated operator-initiated 

commitments be posted in order to help market participants better understand the drivers 

of uplift in each zone and the impact of such commitments on rates. 

86. The Commission requested comments on: (1) the types of unit commitments that 

should be reported as operator-initiated commitments;

160 (2) what it means for a 

commitment to clear the market on the basis of economics;

161 (3) the proposed definition

of “transmission zone,” including the appropriate level of geographic granularity;

162

(4) the proposed reporting timeframe, including potential implementation challenges

particularly with regard to real-time reporting and whether a different reporting 

timeframe would provide sufficient transparency;

163 (5) whether the Commission should 

define a common set of operator-initiated commitment reasons for use across all 

RTOs/ISOs and, if so, what reasons should be included, or whether it is more appropriate 

to allow each RTO/ISO to establish a set of appropriate operator-initiated commitment 

reasons on compliance; and (6) whether the proposal provides sufficient transparency, or 

 160 Id. P 93.

161 Id. P 90.

162 Id. P 91.

163 Id. P 94.
Docket No. RM17-2-000 - 59 -

whether more information is needed (e.g., specific constraint name), as well as any 

potential concerns with requiring additional information.164

2. Comments

87. Several commenters support the proposed requirement that each RTO/ISO report 

operator-initiated commitments in or near real-time and after the close of the day-ahead 

market, with the report including the upper economic operating limit of the committed 

resource in MWs, the transmission zone in which the resource is located, and the reason 

for the commitment.165 Diversified Trading/eXion Energy note that greater transparency 

with respect to operator-initiated commitments will provide incentives for RTOs/ISOs to 

reduce the need for those commitments and ensure that the cost of meeting system needs 

are reflected in market prices.166 Financial Marketers Coalition asserts that transparency 

with respect to the location and reasons for out-of-market and out-of-merit operator 

actions allows financial market participants to understand that a problem is being 

resolved outside of normal market operations and that the day-ahead and real-time 

markets are unlikely to converge through market actions. Financial Marketers Coalition 

 164 Id. P 95.

165 AWEA Comments at 10; Brookfield Comments at 2; Competitive Suppliers 

Comments at 12; Designated Marketers Comments at 6; Diversified Trading/eXion 

Energy Comments at 5; Financial Marketers Coalition Comments at 36; Golden Spread 

Comments at 11-12; NYISO Comments at 8; PJM Market Monitor Comments at 10; 

R Street Institute Comments at 5-6; SPP Market Monitor Comments at 3-4.

166 Diversified Trading/eXion Energy Comments at 5.
Docket No. RM17-2-000 - 60 -

adds that this level of transparency allows any market participant transacting in an area 

where an out-of-market or out-of-merit operator action is being taken to know that it will 

be subjected to uplift allocation exposure.167 Furthermore, Financial Marketers Coalition 

asserts that robust transparency practices allow the marketplace to develop solutions to 

problems.168 R Street Institute states that transparency of operator-initiated commitments 

is important because such commitments often occur when the system is stressed, have a 

sizable effect on market outcomes, and may become more frequent given the penetration 

of meteorologically-sensitive resources. R Street Institute contends that reporting 

operator-initiated commitments by zone and commitment reason is reasonable. R Street 

Institute further contends that reporting on a sub-zonal basis would provide value in areas 

with transmission constraints.169 Other commenters raise concerns or request 

clarification about elements of the proposed requirements as discussed further below.

a. Definition of Operator-Initiated Commitments

88. Three RTOs/ISOs, MISO, NYISO, and PJM, found elements of the proposed 

definition of operator-initiated commitments to be unclear and requested clarification as 

to whether or not certain types of commitments should be reported. MISO argues that the 

proposed definition of operator-initiated commitments as “commitments not associated 

with clearing the day-ahead or real-time market on the basis of economics” may 

 167 Financial Marketers Coalition Comments at 37.

168 Id.

169 R Street Institute Comments at 5-6.
Docket No. RM17-2-000 - 61 -

contradict the statement in the NOPR that commitments made through residual unit 

commitment and look-ahead commitment processes should be reported. MISO requests 

clarification on whether to report residual unit commitments and look-ahead 

commitments because the NOPR specifically states that these commitments should be 

reported even though MISO considers costs when making these commitments. Similarly, 

NYISO requests confirmation that commitments made through its real-time commitment 

and dispatch processes are not intended to be included simply because they consider 

multiple time horizons and thus include look-ahead functionality. NYISO also states that 

its real-time dispatch software can economically evaluate commitments of certain offline

resources that can respond to dispatch instructions within 10 minutes, but that subsequent 

action by the operator is needed to actually dispatch the resource. NYISO states that it 

does not believe the Commission intended these commitments to be considered operatorinitiated commitments for the purposes of this NOPR.170 MISO suggests that as an 

alternative, the Commission could define operator-initiated commitments as those made 

outside of the day-ahead market, whether manual or automated, without consideration of 

total production costs.

171

89. PJM states that it does not have any automated commitments in either the realtime or day-ahead market; instead PJM has a variety of applications that provide 

 170 NYISO Comments at 8-11.

171 MISO Comments at 14-15 (citing NOPR, FERC Stats. & Regs. ¶ 32,721 

at P 90).
Docket No. RM17-2-000 - 62 -

commitment suggestions to PJM operators, who perform additional analyses prior to 

committing any unit. PJM interprets the proposal to require it to post all commitments 

made after the close of the day-ahead market. PJM states that it is able to accomplish this 

goal, but requests confirmation that this was the intent of the proposal.172

b. Confidentiality, Market Power, and CEII

90. Several RTOs/ISOs state that the proposed operator-initiated commitment reports 

could reveal resource-identifiable or competitive information, or lead to market power 

concerns.173 MISO claims that the proposed report may not protect the data of individual 

market participants and may reveal identifiable competitive information.174 MISO states 

that it does not post commitment data by resource or provide the name or transmission 

zone of the committed resources to avoid disclosure of confidential information that may 

harm market participants and create risks in MISO’s competitive markets. Instead, MISO 

aggregates posted commitment data by commitment reason.175 MISO does not support 

posting commitment information by resource, and argues that if the Commission does 

require reporting of locational information that it should allow RTOs/ISOs to aggregate 

transmission zones when posting commitment data, as there could be transmission zones 

 172 PJM Comments at 13-14.

173 ISO-NE Comments at 44; MISO Comments at 18; SPP Comments at 3-4.

174 MISO Comments at 18.

175 Id. at 17.
Docket No. RM17-2-000 - 63 -

that have a single asset owner. MISO adds that the use of existing transmission zone 

aggregations should be allowed in each RTO/ISO instead of creating new transmission 

zone aggregations.176 ISO-NE and NYISO both state that they could report additional 

information to comply with this requirement.177 NYISO notes, however, that it may be 

necessary to modify existing mitigation rules or potentially create new rules to address 

market power or anti-competitive behavior concerns that may arise from the requirements 

of any final rule.178 Similarly, ISO-NE contends that, in any final rule, the Commission 

should allow each RTO/ISO to propose rules or procedures that may be necessary to 

address market power issues.

179 SPP contends that the operational characteristics of 

resources, including their economic maximums, are competitive information and should 

not be posted.180 

91. Responding to SPP, XO Energy states that the proposed report would not require 

SPP to identify the unit that was committed.181 XO Energy states that, for confidentiality 

reasons, specific names of resources should not be posted, but that the information posted 

 176 Id. at 18.

177 ISO-NE Comments at 44; NYISO Comments at 8-9.

178 NYISO Comments at n. 28.

179 ISO-NE Comments at 44.

180 SPP Comments at 3-4.

181 XO Energy Reply Comments at A-9.
Docket No. RM17-2-000 - 64 -

should be as granularly specific as possible.182 XO Energy points to MISO’s operatorinitiated commitment reports as an example of the granularity that should be provided in 

a report.183 EEI suggests that RTOs/ISOs protect confidentiality by making the 

information available only to market participants.184

92. ISO-NE and PJM raise concerns that the proposed operator-initiated commitment 

reports could reveal Critical Energy/Electric Infrastructure Information (CEII).

185 ISONE states that detailed reporting in real-time on operator-initiated actions could raise 

system security issues and argues that, in any final rule, the Commission should permit 

each RTO/ISO to propose rules or procedures to protect CEII.186 PJM explains that the 

identification of specific resources committed to control specific transmission constraints 

is CEII and should not be published.187 In response to PJM, XO Energy argues that many 

 182 XO Energy Replacement Comments at 34-35.

183 Id. at 35.

184 EEI Comments at 9.

185 18 CFR § 388.113 (2017). See also Regulations Implementing FAST Act 

Section 61003 - Critical Electric Infrastructure Security and Amending Critical Energy 

Infrastructure Information, Order No. 833, 81 Fed. Reg. 93,732 (Dec. 21, 2016), FERC 

Stats. & Regs. ¶ 31,389 (2016).

186 ISO-NE Comments at 44.

187 PJM Comments at 14.
Docket No. RM17-2-000 - 65 -

market participants have clearance from the Commission to access CEII data and these 

participants should be able to access any and all CEII data.188

c. Commitment Reasons

93. Several commenters responded to the request for comment on whether the 

Commission should define a common set of commitment reason categories and, if so, 

which categories should be included, or whether it is more appropriate to allow each 

RTO/ISO to establish a set of commitment reasons on compliance.189 MISO contends

that regional flexibility should be allowed for each RTO/ISO to establish an appropriate 

set of commitment reason categories. MISO further argues that prescribing a set of 

categories may lead to confusion and disruption of established processes that may 

provide the desired transparency, but in a manner that does not fit the prescribed 

categories.190 TAPS similarly urges the Commission to leave it to individual RTOs/ISOs

to determine how best to comply with reporting requirements.191

94. Conversely, PJM and EEI support the Commission defining a minimum set of 

categories to be used by RTOs/ISOs that identify the reasons for the commitment.192 

PJM requests that the Commission allow each RTO/ISO to develop its own additional 

 188 XO Energy Reply Comments at A-7.

189 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 95.

190 MISO Comments at 15-16; TAPS Comments at 9.

191 TAPS Comment at 9.

192 EEI Comments at 9; PJM Comments at 14.
Docket No. RM17-2-000 - 66 -

categories because RTOs/ISOs have different market designs and operational practices. 

Similarly, EEI argues that RTOs/ISOs should have the flexibility to provide more 

granular, detailed, or relevant information, as needed.193 MISO also suggests that the 

Commission could alternatively require that the categories that each RTO/ISO establishes 

should, at a minimum, reflect the uplift categories the NOPR proposes.

194 PJM states that 

it is unclear what level of detail the Commission is contemplating for these categories and 

argues that a Final Rule should clarify the level of detail envisioned.195 

d. Reporting Timeline

95. Several RTOs/ISOs discussed their current reporting practices and whether it is 

feasible to meet the proposed requirement to report real-time operator-initiated 

commitments within four hours.

196 MISO states that it currently posts economic and 

constraint management commitments, excluding those made in the day-ahead market, to 

its public website on a real-time and historical basis. In addition, MISO notes that 

historical information is included in the Real-Time Revenue Sufficiency Guarantee 

Commitments report, which is updated daily with a one-day lag. MISO states that the 

posted commitment information includes an aggregation of the hourly economic 

 193 EEI Comments at 9.

194 MISO Comments at 15-16.

195 PJM Comments at 14.

196 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 94.
Docket No. RM17-2-000 - 67 -

maximum limit of committed resources by commitment reason, and the total number of 

resources committed by commitment reason (either capacity or constraint name).197 

MISO requests guidance as to whether the four-hour timeframe will be counted from the 

time the commitment notification is issued, the beginning of the commitment period, or 

the start of the current market interval.198 ISO-NE and PJM state that they would likely 

be able to comply with the proposed reporting of operator-initiated commitments. PJM 

requests that any Final Rule provide flexibility in the reporting timeframe so that, in the 

event of unforeseen technical issues, PJM is not exposed to a compliance violation.199

NYISO states that it already posts information regarding many operator-initiated 

commitments in real-time and generally supports the proposed reforms but, as noted 

above, would need to report on additional commitments and add both the location and 

upper operating limit of each resource included in its report.

200

96. On the other hand, CAISO states that it produces operator-initiated commitment 

reports manually because they require collecting operator log information and presenting 

it in a reporting format. Therefore, CAISO states that it cannot provide the required 

 197 MISO Comments at 17 (MISO states that the data is described as pertaining to 

“3 or less resources” when the number of committed resources is less than or equal to 

three).

198 Id. at 16.

199 PJM Comments at 14.

200 NYISO Comments at 8-9.
Docket No. RM17-2-000 - 68 -

operator-initiated commitment information within the four-hour deadline.201 CAISO 

further contends that there is no reason the requested information should be required 

within four hours as it is not clear what actions market participants can take to address 

these issues under the proposed timeline. CAISO argues that market participants can 

better evaluate issues raised due to exceptional dispatches by analyzing monthly trends. 

CAISO states that it already provides much of this information on a monthly basis, and 

argues that the Commission should modify its proposal to allow RTOs/ISOs to post 

information as part of existing monthly reports that they already provide.202

97. In response to CAISO's concerns, XO Energy states that it disagrees with 

CAISO’s assertion that expediting reporting of operator-initiated commitments is not 

feasible because these systems are already in place in other RTOs/ISOs. XO Energy 

asserts that the commitment of units must be recorded into a database because this 

information is used for settlement purposes and dispatch instructions are sent 

electronically to resources and incorporated into the next SCED calculation. XO Energy 

states that these commitments can and should be posted in real-time as they occur.203

XO Energy asserts that knowledge that a unit was committed by operator action may 

indicate an inefficiency in the system that is not currently reflected in published prices, 

 201 CAISO Comments at 14.

202 Id. at 14-15.

203 XO Energy Reply Comments at A-3.
Docket No. RM17-2-000 - 69 -

presenting an opportunity to solve that issue through normal market activity. XO Energy 

argues that if this information is delayed by even four hours, the opportunity to place bids 

to address that inefficiency may pass.204 XO Energy contends that market participants 

that own the units being dispatched have access to operator-initiated commitment 

information; market participants without physical assets are disadvantaged because they 

do not currently have access to this data and are underrepresented in the stakeholder 

process.205 Competitive Suppliers argue that real-time commitments need to be posted as 

soon as practical after they occur, not later than four hours after the commitment, to help 

market participants understand uplift.

206 R Street Institute contends that the proposed 

temporal requirements are reasonable and already met by NYISO, MISO, and CAISO.207

e. Other Issues

98. Some commenters suggest that RTOs/ISOs should be required to post other types 

of commitments or additional information. XO Energy asserts that there is a substantial 

amount of operator discretion in the day-ahead market and that all resources that 

contribute to day-ahead or real-time uplift should be reported.208 Competitive Suppliers 

state that the definition should also include other operator-initiated actions that impact 

 204 Id. at A-3.

205 Id. at A-1.

206 Competitive Suppliers Comments at 12.

207 R Street Institute Comments at 5-6.

208 XO Energy Replacement Comments at 35.
Docket No. RM17-2-000 - 70 -

uplift, such as load biasing. Furthermore, Competitive Suppliers argue that selfscheduled units should be reported when they are called on to alleviate an issue that 

would have resulted in some uplift payment had the unit not been self-scheduled.

209 

Golden Spread requests that the Commission include the reporting of certain transactions 

in the day-ahead market that can impact LMPs and cause uplift, such as excess rampable 

capacity in SPP that has been moved into the day-ahead market.210 EEI argues that in 

addition to generator information, RTOs/ISOs should publish criteria used to make 

decisions with regard to reserve levels, conservative operations, import levels, and other 

operational constraints. EEI contends that identifying the types of costs or transactions 

included in uplift payments, and which of those should be included in LMPs will help 

inform potential changes to market rules around out-of-market actions.211

3. Determination

99. We adopt the NOPR proposal and require each RTO/ISO to post all operatorinitiated commitments on its website, subject to the modifications and clarifications 

discussed below. Operator-initiated commitments are made to address system needs, but 

because they are made outside of the market are inherently less transparent. As stated in 

the NOPR, transparency into operator-initiated commitments is important because such 

 209 Competitive Suppliers Comments at 10-11.

210 Golden Spread Comments at 12-13.

211 EEI Comments at 9-10.
Docket No. RM17-2-000 - 71 -

commitments can affect energy and ancillary service prices and can result in uplift. 

Greater transparency will allow stakeholders to better understand the drivers of uplift 

costs, assess an RTO’s/ISO’s operator-initiated commitment practices, and raise any 

issues of concern through the stakeholder process.212 We find that the basis for this 

requirement as outlined in the NOPR remains compelling. The Operator-Initiated 

Commitment Report will provide granular information about the location, timing, causes 

and size of operator-initiated commitments. Such information will allow stakeholders to 

better understand the connections between system needs and operator actions and to 

make investments in facilities and equipment where most needed by the system, thus 

potentially improving market efficiency. We address commenters’ concerns below. 

100. Based on the comments, we adopt a modified definition of an operator-initiated 

commitment for the purpose of this Final Rule. We agree with MISO and NYISO that 

the proposed definition of operator-initiated commitments as “commitments not 

associated with clearing the day-ahead or real-time market on the basis of economics” 

may contradict the clarification in the NOPR that the proposed definition includes 

commitments made through look-ahead processes,213 particularly if an RTO/ISO process 

commits units on the basis of economics and includes look-ahead functionality. Further, 

as we noted in the NOPR, whether a commitment cleared the market on the basis of 

economics may be a point of confusion. In order to be more precise, we therefore modify 

 212 NOPR, FERC Stats. & Regs. ¶ 32,721 at PP 92-93.

213 Id. P 90.
Docket No. RM17-2-000 - 72 -

the definition of an operator-initiated commitment to be a commitment after the dayahead market, whether manual or automated, for a reason other than minimizing the total 

production costs of serving load. RTO/ISO market software generally minimizes total 

production costs subject to certain reliability constraints. Such software may make 

commitments to meet needs for additional supply due to changing market conditions or 

variations from forecast after the day ahead market. These commitments reflect the next 

marginal supply to meet load and minimize total production costs and are thus exempt 

from this reporting requirement. In contrast, because some constraints cannot be 

included in market software, RTOs/ISOs may need to make some commitments to 

address reliability considerations that are not modeled in the market software. Because 

these considerations are not included in the software, they may not minimize total 

production costs and thus should be reported. Such commitments are not likely to be 

reflected in market prices and may result in uplift costs. Thus, unlike the NOPR 

proposal, the definition adopted here does not include commitments made through lookahead commitment processes that minimize total production costs. Consistent with the 

NOPR proposal, this definition excludes self-schedules. We expect that by not explicitly 

requiring the inclusion of look-ahead commitments, this modified definition will likely 

reduce the number of commitments that RTOs/ISOs are required to report compared to 

the definition proposed in the NOPR, but the modified definition will focus RTO/ISO 

reporting on commitments of those resources whose offers are least likely to be reflected 

in day-ahead and real-time prices and are therefore most likely to result in uplift costs. 

101. PJM requests clarification that we intend to require PJM to report all commitments 
Docket No. RM17-2-000 - 73 -

made by operators occurring after the close of the day-ahead market because it has no 

“automated” commitments. We clarify that when an automated process makes a 

recommendation to an operator who makes the final decision, the commitment must be 

reported if the underlying process did not minimize total production costs. However, we 

are aware that RTOs/ISOs have a variety of processes through which units can be 

committed. On compliance, we therefore require each RTO/ISO to indicate, for each 

commitment process (whether automated or manual) that executes after the day-ahead 

market, whether it believes our modified definition implicates some or all commitments 

from the process and justify any commitments that it does not plan to report.

102. After considering commenters’ responses to the questions the Commission asked 

about the reporting timeframe, potential implementation challenges of reporting in realtime, and whether a different reporting timeframe would provide sufficient 

transparency,214 we find that requiring operator-initiated commitments to be posted no 

later than four hours after the commitment may place an unnecessary burden on some 

RTOs/ISOs. Therefore, we require that each RTO/ISO post this information on its 

website in machine-readable format as soon as practicable but no later than 30 days after 

the end of the month. However, we note that the timing of operator-initiated 

commitments is important to understanding system conditions surrounding those 

commitments, and was implicit in the proposed four-hour deadline. Because we no 

longer require near-real-time reporting of operator-initiated commitments, we instead will 

 214 Id. P 94.
Docket No. RM17-2-000 - 74 -

require each RTO/ISO to include in its report the start time of each commitment in order 

to enable stakeholders to understand system conditions surrounding the commitment. 

While we are providing each RTO/ISO significant flexibility in when it must report 

operator-initiated commitments, we encourage each RTO/ISO to design its processes so 

that this information is provided to market participants as soon as possible. 

103. We adopt the NOPR proposal to require RTOs/ISOs to report the size of each 

commitment. In the NOPR, we described this value as the upper economic operating 

limit of the committed resource in MW (i.e., its economic maximum).

215 We continue to 

believe this requirement will provide transparency into the size of the system need 

associated with the operator-initiated commitment. However, RTOs/ISOs may propose, 

on compliance, an alternative metric and must demonstrate that it provides transparency 

into the size of the system need associated with the operator-initiated commitment that is 

consistent with or superior to that provided by the economic maximum of each 

committed resource. This should address SPP’s assertion that this resource parameter 

should not be posted because it is considered competitive information. 

104. As with the Zonal Uplift Report discussed above, we adopt the NOPR proposal 

and define “transmission zone” as a geographic area that is used for the local allocation 

of charges and find that this definition balances the benefits of greater transparency with 

the desire to preserve a reasonable level of protection of potentially commerciallysensitive information. As discussed above, RTOs/ISOs may have multiple existing types 

 215 Id. P 91.
Docket No. RM17-2-000 - 75 -

of zones that could meet our definition. We believe that there are transparency benefits 

to using the same set of zones for the Zonal Uplift Report and the Operator-Initiated 

Commitment Report. However, we acknowledge that an RTO/ISO may have a legitimate 

reason for using a more or less granular set of zones for one or the other of the 

two reports and the decision to provide less granularity on one report does not necessitate 

less granularity for both reports simply to maintain consistency between reports. On 

compliance, we require each RTO/ISO to include in its tariff the type of zone that it 

proposes to use in its Operator-Initiated Commitment Report, explain how the chosen 

type of zone meets the definition of transmission zone adopted in this Final Rule, and 

provide justification for any differences between the sets of zones used for the two 

reports.

105. We adopt the NOPR proposal and require that the Operator-Initiated Commitment 

Reports include the reason for each commitment. In the NOPR, the Commission

requested comment as to whether the Commission should define a common set of 

categories of commitment reasons for use across all RTOs/ISOs and, if so, what reasons

should be included, or whether to allow each RTO/ISO to establish a set of appropriate 

operator-initiated commitment reasons on compliance. As EEI suggests, requiring a 

common set of commitment reasons will help ensure that RTOs/ISOs provide similar 

information to market participants. This consideration is balanced against the desire for a 

minimum set of commitment reasons that are not so broad as to provide limited inference 

about the nature of the reliability consideration addressed through the commitment. 

While no specific commitment reasons were suggested by commenters, the potential
Docket No. RM17-2-000 - 76 -

commitment reasons listed in the NOPR216 appear to be consistent with the broad reasons 

for which RTOs/ISOs make operator-initiated commitments. Therefore, we require that 

RTOs/ISOs, include, at a minimum, the following three commitment reasons: systemwide capacity, constraint management, and voltage support. However, we acknowledge 

that RTOs/ISOs may use different terminology or have other reasons for making 

operator-initiated commitments that do not minimize total production costs. Therefore, if

RTOs/ISOs would like to include additional or more detailed commitment reasons in 

their Operator-Initiated Commitment Reports, they may do so. 

106. We clarify that we are not requiring that RTOs/ISOs identify resource names or

specific constraints in the Operator-Initiated Commitment Report. We also clarify, in 

response to concerns from PJM and ISO-NE that each RTO/ISO is permitted to propose,

upon compliance, modifications to the report to avoid disclosing information that could 

be used to harm system security. 

107. In response to NYISO’s and ISO-NE’s comments that it may be necessary to 

create new rules or procedures to address market power or anti-competitive behavior that 

may arise as a result of this report we note that any such rules or procedures would be 

outside the scope of this proceeding. RTOs/ISOs may propose any further changes they 

deem appropriate in a separate filing pursuant to section 205 of the Federal Power Act.217

 216 Id. P 95 and n.109.

217 16 U.S.C. § 824d.
Docket No. RM17-2-000 - 77 -

108. We also confirm that RTOs/ISOs may choose to report more information about 

operator-initiated commitments or other operator actions. However, we find that requests 

by several commenters to require reporting of other types of commitments or other 

operator actions that may affect uplift are beyond the scope of this proceeding, as this 

requirement only addresses operator-initiated commitments.

D. Transmission Constraint Penalty Factors

1. NOPR Proposal

109. In the NOPR, the Commission proposed to require each RTO/ISO to include, in its 

tariff: its transmission constraint penalty factor values; the circumstances, if any, under

which the transmission constraint penalty factors can set LMPs; and the procedure, if 

any, for temporarily changing the transmission constraint penalty factor values. The 

Commission further proposed that any procedure for temporarily changing transmission 

constraint penalty factor values must provide for notice of the change to market 

participants.

218

110. The Commission reasoned that transparency into transmission constraint penalty 

factors and associated practices is important because the penalty factors and practices can 

affect prices. Without an understanding of the level of transmission constraint penalty 

factors or under what circumstances they can set LMPs or be temporarily changed, 

 218 NOPR, FERC Stats. & Regs. ¶ 32,721 at Regulatory Text.
Docket No. RM17-2-000 - 78 -

market participants may not be able to hedge transactions appropriately or raise concerns 

into RTO/ISO practices through the stakeholder process.219 

2. Comments

111. Many commenters support the proposed requirement that all RTOs/ISOs include 

provisions related to transmission constraint penalty factors in their tariffs.220 Potomac 

Economics explains that transmission constraint penalty factors represent the maximum 

re-dispatch cost that a RTO/ISO will incur to resolve congestion on a constraint, and are 

generally used to set the congestion components of LMPs when a constraint is violated. 

Because penalty factors can set prices and affect dispatch, Potomac Economics supports 

requiring RTOs/ISOs to file transmission constraint penalty factors, and any provisions to 

adjust them, in their tariffs to be reviewed and approved by the Commission.221 

Competitive Suppliers state that transmission constraint penalty factors affect prices and 

uplift, so transparency around their use is important for market participants to understand 

their impact.222 MISO asserts that transparency around transmission constraint penalty 

 219 Id. P 80.

220 APPA/NRECA Comments at 12-13; AWEA Comments at 10; Competitive 

Suppliers Comments at 10; Designated Marketers Comments at 6; Direct Energy 

Comments at 10; EEI Comments at 10; Financial Marketers Coalition Comments at 45;

Golden Spread Comments at 5; MISO Comments at 19; NYISO Comments at 1; PJM 

Comments at 15; PJM Market Monitor Comments at 10; Potomac Economics Comments 

at 12-13; R Street Institute Comments at 6; TAPS Comments at 10; XO Energy 

Replacement Comments at 37, 39.

221 Potomac Economics Comments at 12-13.

222 Competitive Suppliers Comments at 10.
Docket No. RM17-2-000 - 79 -

factors can increase confidence that market outcomes are rational and encourage dialogue 

to improve market efficiency, while Financial Marketers Coalition asserts that a lack of 

transparency around these practices can lead to confusion and uncertainty in 

understanding and forecasting prices.223 No commenters express opposition to the 

requirements proposed in the NOPR.

112. Several RTOs/ISOs state that they currently comply, plan to comply, or could 

comply with the proposed requirements. MISO and MISO Transmission Owners assert

that MISO’s tariff is consistent with the proposal.224 MISO also notes that it posts 

shadow prices, transmission constraint penalty factors, and reasons for temporary 

overrides of transmission constraint penalty factors in reports on its website.225 CAISO 

states that its tariff already contains the penalty factors and their impacts on market 

outcomes for each of its markets and market calculations.226 NYISO intends to file tariff 

revisions with the Commission independent of the NOPR, which will align with the 

proposed requirements of the NOPR.227 PJM supports including certain provisions 

 223 Financial Marketers Coalition Comments at 45; MISO Comments at 18.

224 MISO Comments at 18-19 (citing Schedule 28A of its Tariff); MISO 

Transmission Owners Comments at 5 n.17.

225 MISO Comments at 19.

226 CAISO Comments at 11-12.

227 NYISO Comments at 12. Since its comments, NYISO has subsequently filed 

transmission constraint pricing tariff revisions with the Commission. N.Y. Indep. Sys. 

Operator, Inc., Docket No. ER17-1453-000 (June 14, 2017) (delegated letter order).
Docket No. RM17-2-000 - 80 -

related to transmission constraint penalty factors in its tariff.228 The PJM Market Monitor 

explains that it has recommended that PJM include transmission constraint penalty factor

values in its tariff, and explicitly state its policy on the use of these penalty factors in 

setting LMP, the appropriate triggers of these penalty factors, and when they should be 

used to set the shadow prices of transmission constraints.229 ISO-NE allows that it could 

specify more information on transmission constraint penalty factors in its tariff.230

113. Several commenters explicitly support the proposal requiring RTOs/ISOs to 

explain in their tariffs when transmission constraint penalty factors can set LMPs, if 

ever.

231 Potomac Economics, XO Energy, and R Street Institute explain that when a 

constraint is violated, some RTOs/ISOs relax the constraint to reduce the shadow price to 

less than the penalty factor, which reduces congestion components of LMPs.232 Potomac 

Economics explains that if, for example, an RTO/ISO has a penalty factor of $1,000 and 

 228 PJM Comments at 15.

229 PJM Market Monitor Comments at 10 (citing PJM, 2015 Annual State of the 

Market Report, v. 2, Section 3: Energy Market (March 2016), 

http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2015/2015-sompjm-volume2-sec3.pdf).

230 ISO-NE Comments at 44-45. 

231 Competitive Suppliers Comments at 10; EEI Comments at 10; Financial 

Marketers Coalition Comments at 45; Golden Spread Comments at 5; PJM Market 

Monitor Comments at 10; Potomac Economics Comments at 16; R Street Institute 

Comments at 6; XO Energy Replacement Comments at 37.

232 Potomac Economics Comments at 14-15; R Street Institute Comments at 6; 

XO Energy Comments at 37-39.
Docket No. RM17-2-000 - 81 -

the unit that is re-dispatched to manage the constraint has a marginal cost of $999, the 

congestion will be determined by the $999 shadow price. However, if the RTO/ISO 

relaxes the constraint, thereby diminishing reliability, the “relaxed” shadow price that 

determines the congestion cost may be well below the penalty factor.233

114. R Street Institute argues that relaxing transmission constraints to prevent penalty 

factors from setting prices distorts congestion price formation, which undermines 

efficient commitment and dispatch in the short term and distorts market investments and 

retirements in the long term.234 XO Energy asserts that penalty prices are in place to 

improve price formation when all economic actions are exhausted, and that constraint 

relaxation masks the underlying violation.235 XO Energy further argues that RTOs/ISOs 

that do not allow penalty factors to set price should explain and justify the conditions for 

relaxing a constraint.236 Financial Marketers Coalition states that arbitrary standards on 

when transmission constraint penalty factors can set LMPs can afford considerable 

discretion to dispatchers and can lead to confusion among market participants.237 

 233 Potomac Economics Comments at 14-15.

234 R Street Institute Comments at 6.

235 XO Energy Comments at 38.

236 Id. at 37.

237 Financial Marketers Coalition Comments at 45.
Docket No. RM17-2-000 - 82 -

115. Potomac Economics suggests that the Commission not only require RTOs/ISOs to 

explain how penalty factors contribute to setting LMP, but require that penalty factors set 

shadow prices for violated constraints.238 The PJM Market Monitor agrees that penalty 

factors should affect LMPs in the same manner that generator offer prices affect LMPs,

so if the flow on a transmission constraint exceeds the line limit, the shadow price of the

constraint should equal the transmission constraint penalty factor.239

116. Multiple commenters explicitly support the proposed requirement that RTOs/ISOs 

include in their tariffs any procedures for changing penalty factors and provide notice of 

any such changes to market participants.240 Potomac Economics states that it has 

observed RTOs/ISOs increasing or decreasing the transmission constraint penalty factors 

in real-time operations for a variety of reasons.241 Potomac Economics states that 

RTOs/ISOs generally increase a penalty factor when a violation raises more serious 

reliability concerns than normal and decrease a factor in real-time to reduce the real-time 

congestion pricing for a violated constraint. Potomac Economics states that whether 

increasing or decreasing the factors, these actions can profoundly affect LMPs, unit 

 238 Potomac Economics Comments at 16.

239 PJM Market Monitor Comments at 11.

240 EEI Comments at 10; Golden Spread Comments at 5; PJM Market Monitor 

Comments at 10; R Street Institute Comments at 5; XO Energy Replacement Comments 

at 39.

241 Potomac Economics Comments at 12 -13.
Docket No. RM17-2-000 - 83 -

commitments, dispatch levels, and reliability, and therefore RTOs/ISOs should file any 

provisions to adjust them.242

117. XO Energy states that MISO currently posts any overridden transmission 

constraint demand curves through its real-time market and provides reasons for such 

overrides in its next-day market reports.243 In contrast, XO Energy notes that PJM does 

not provide any indication or rationale for changing transmission constraint penalty 

factors, but generally performs a price correction the following day that is only evident 

through increased or decreased shadow prices.244 ISO-NE and TAPS state that tariff 

provisions on transmission constraint penalty factors should be flexible enough to permit 

system operators to modify these factors in real-time to maintain reliability of the system 

and otherwise temporarily change these values to account for changes in system 

conditions.245 CAISO states that while it currently cannot temporarily change penalty 

prices, it does not object to obtaining such flexibility in its tariff or to describing in its 

tariff the relevant conditions for utilizing such flexibility.246

 242 Id. at 13 -14. 

243 XO Energy Replacement Comments at 39-40.

244 Id. at 40.

245 ISO-NE Comments at 44-45; TAPS Comments at 10. 

246 CAISO Comments at 11-12.
Docket No. RM17-2-000 - 84 -

118. Potomac Economics makes two recommendations to strengthen the requirement to 

file transmission constraint penalty factors. Potomac Economics states that the 

Commission should require or encourage RTOs/ISOs to file multi-point demand curves, 

as in MISO and NYISO, rather than single penalty values because demand curves 

demonstrate that the size of the violation matters from a reliability perspective. 

XO Energy also supports the implementation of the demand curve approach used in 

MISO.247

119. Potomac Economics also suggests that the Commission clarify that penalty values 

should correspond to the reliability concerns that arise when constraints are violated. 

Potomac Economics states that, while estimating the reliability value of a transmission 

constraint can be challenging, reasonable values can be set that reflect the relative 

reliability concern associated with violating different constraints.

248

120. XO Energy states that RTO/ISO actions to affect the percentages of thermal limits 

used for controlling constraints also can mask violations of thermal limits and affect how 

high shadow prices can bind. XO Energy therefore suggests enhancing the transparency 

of operator actions surrounding Limit Controls.249 

 247 XO Energy Replacement Comments at 43.

248 Potomac Economics Comments at 14.

249 XO Energy Replacement Comments at 36, 39 (citing PJM, Transmission 

Constraint Control Logic in Market Clearing Engines (March 2017), 

http://www.pjm.com/~/media/committees-groups/committees/mic/20170308/20170308-

informational-only-transmission-constraint-control-logic-in-mces.ashx). 
Docket No. RM17-2-000 - 85 -

3. Determination

121. We adopt the NOPR proposal and require that each RTO/ISO include in its tariff

on an on-going basis: (1) the transmission constraint penalty factor values used in its 

market software;

250 (2) the circumstances, if any, under which the transmission constraint 

penalty factors can set LMPs;

251 and (3) the procedures, if any, for temporarily changing 

transmission constraint penalty factor values. We also require that any procedures for 

temporarily changing transmission constraint penalty factor values must provide for 

notice of the change to market participants as soon as practicable.

252 We find that 

transmission constraint penalty factors have the potential to materially affect energy and 

ancillary services prices so they should be included in the tariff. Further, greater 

transparency into transmission constraint penalty factors will allow market participants to 

understand how an RTO’s/ISO’s actions and practices affect clearing prices. We agree 

with commenters that, without transparency into transmission constraint penalty factors, 

market participants cannot understand the impact of these factors on LMPs or effectively 

 250 As proposed in the NOPR, if the RTO/ISO includes different transmission 

constraint penalty factors for different purposes (e.g., unit commitment and economic 

dispatch, day-ahead versus real-time), we require that all sets of transmission constraint 

penalty factors be included in the tariff. See NOPR, FERC Stats. & Regs. ¶ 32,721 at P 

97.

251 As proposed in the NOPR, RTOs/ISOs should provide explanations in their 

tariffs if they have different processes for allowing transmission constraint penalty factors 

to set LMPs in different circumstances, as well as any specific restrictions or conditions 

under which transmission constraint penalty factors are allowed to set LMPs. NOPR, 

FERC Stats. & Regs. ¶ 32,721 at P 98.

252 NOPR, FERC Stats. & Regs. ¶ 32,721 at PP 96-99.
Docket No. RM17-2-000 - 86 -

engage in dialogue or transactions to improve market efficiencies. Accordingly, we 

adopt the proposal in the NOPR. On compliance, each RTO/ISO is required to include 

its current transmission constraint penalty factors and associated current practices in its

tariff. The three Transmission Constraint Penalty Factor Requirements also apply to any 

subsequent changes to an RTO’s/ISO’s penalty factor values and practices.

122. We clarify that we are not requiring RTOs/ISOs to have procedures to temporarily 

change their transmission constraint penalty factor values. Rather, if an RTO/ISO 

currently has the flexibility to temporarily override transmission constraint penalty factor 

values, for example, to account for reliability concerns, the circumstances under which 

the factors may be changed and any procedures for doing so must be included in the 

RTO’s/ISO’s tariff. We appreciate requests that the Commission require RTOs/ISOs to 

adopt specific practices in developing transmission constraint penalty factors and 

specifications for how transmission constraint penalty factors can set LMPs. However, 

we find that such requests go beyond the scope of this rule, which is focused on 

transparency into current RTO/ISO practices related to transmission constraint penalty 

factors. Accordingly, we will not address those requests here. Further, RTOs/ISOs may 

propose any changes they deem appropriate to their current practices related to 

transmission constraint penalty factors in a separate filing pursuant to section 205 of the 

Federal Power Act.253 

 253 16 U.S.C. § 824d.
Docket No. RM17-2-000 - 87 -

E. Other Comments Requested

1. Reporting of Transmission Outages

123. In the NOPR, the Commission requested comment on whether additional reporting 

of transmission outages should be required, noting that transmission outages are an 

important facet of price formation because they can affect RTO/ISO commitment and 

dispatch decisions and resulting market clearing prices.

254 

a. Comments

124. Most RTOs/ISOs state that they already provide information on transmission 

outages. MISO states that it posts all transmission outages on OASIS on an hourly 

basis.255 ISO-NE states that it currently posts both long- and short-term reports on 

transmission outages, updated on a daily and 15-minute basis, respectively.256 NYISO 

states that it posts information regarding scheduled and actual outages of 100 kV and 

higher transmission facilities on its website in machine-readable format.

257 PJM states

that it posts outages on its website.258 

125. Several commenters support additional transparency into transmission outages.259 

 254 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 98.

255 MISO Comments at 19.

256 ISO-NE Comments at 45.

257 NYISO Comments at 12.

258 PJM Comments at 15.

259 AWEA Comments at 10; Direct Energy Comments at 10; Diversified 

Trading/eXion Energy Comments at 5-7; EDF Comments at 1-5; PJM Market Monitor 
Docket No. RM17-2-000 - 88 -

The PJM Market Monitor asserts that more consistent and timely outage reporting is 

important to transparency.

260 Potomac Economics and AWEA argue that additional 

reporting of transmission outages would improve market efficiency and reduce 

uncertainty for participants.261

126. XO Energy contends that all RTOs/ISOs should be required to post all known 

transmission outages in real-time at the same frequency as real-time dispatch, using EMS 

model detail. XO Energy also contends that planned and emergency outages known and 

included in the day-ahead market solution should be included as an additional report 

posted with each RTO/ISO day-ahead market solution.262 

127. Diversified Trading/eXion Energy and XO Energy contend that RTOs/ISOs 

should be required to post all outages that are modified or cancelled after the close of the 

day-ahead market, as well as the impact of cancelled outages on prices and uplift. 

Diversified Trading/eXion Energy further contend that this posting should also include 

 

Comments at 11; Potomac Economics Comments at 11-12; XO Energy Replacement 

Comments at 43-45.

260 PJM Market Monitor Comments at 11.

261 AWEA Comments at 10; Potomac Economics Comments at 11-12.

262 XO Energy Replacement Comments at 43-44.
Docket No. RM17-2-000 - 89 -

the reason for the cancellation or modification, the transmission owner, and the frequency 

with which the transmission owner has cancelled or modified outages after the cut-off.263 

128. EDF asserts that there is a need for RTOs/ISOs to incorporate economic 

assessments into their transmission outage scheduling practices and moves that the 

Commission establish a technical conference to address the impact of transmission 

outages on RTO/ISO commitment and dispatch decisions and resulting market clearing 

prices.264 EDF contends that RTOs/ISOs typically only assess the reliability impact of 

outages and do not consider economic impacts. EDF contends that an economic 

assessment of transmission outages should be possible, at relatively low cost, most of the 

time, with no reliability impact, given sufficient advanced planning.265 

129. On the other hand, MISO and PJM contend that additional reporting requirements 

are unnecessary,266 while MISO Transmission Owners contend that any further reporting 

requirements may be duplicative.267 Several commenters also bring up confidentiality 

concerns. PJM argues that posting additional information may risk releasing confidential 

market participant information because the status of a unit or station would be identified 

 263 Diversified Trading/eXion Energy Comments at 5-7; XO Energy Replacement 

Comments at 44-45.

264 EDF Comments at 1.

265 Id. at 5.

266 MISO Comments at 19; PJM Comments at 12.

267 MISO Transmission Owners Comments at 15.
Docket No. RM17-2-000 - 90 -

via this posting.268 MISO Transmission Owners similarly state that outage information 

may contain CEII or other confidential information that should not be identified 

publicly.269 MISO Transmission Owners contend that transmission outages are not fully 

explored in the NOPR and may be better left to a future rulemaking.270 Finally, ISO-NE 

notes that outages that only impact specific generation or other supply resources are 

considered market sensitive and excluded from reports. However, ISO-NE states that 

stakeholders have discussed whether to expand current reporting practices to include the 

market sensitive outages in reports.271

b. Determination

130. We appreciate the input from multiple commenters on the reporting of 

transmission outages. In the NOPR, the Commission sought comment on this topic but 

did not make a specific proposal. Accordingly, based on the record in this proceeding, 

we will not require additional reporting for transmission outages at this time. 

2. Availability of Market Models

131. In the NOPR, the Commission requested comment on whether certain classes of 

market participants are prohibited from obtaining the network models in certain 

RTOs/ISOs and the justification for any such restrictions. The Commission defined 

 268 PJM Comments at 15.

269 MISO Transmission Owners Comments at 15; PJM Comments at 15.

270 MISO Transmission Owners Comments at 14-15.

271 ISO-NE Comments at 45.
Docket No. RM17-2-000 - 91 -

“network model” as “the RTO’s/ISO’s model used in its energy management system for 

the real-time operation of the transmission system (e.g., state-estimation, contingency 

analysis).”272

a. Comments

132. Financial Marketers Coalition and XO Energy explain that there are several 

different types of market models and discuss the varying availability of different market 

models between market participant classes across RTOs/ISOs. XO Energy asserts that 

MISO and SPP provide a fair amount of detail and that PJM, NYISO, and CAISO 

provide the least amount of model detail.273 

133. ISO-NE and MISO state they provide network models to all market 

participants.274 However, NYISO and PJM state that market models are only available to 

a subset of market participants.275 NYISO explains that its network model is only 

available to participants in the Transmission Congestion Market, upon request. NYISO 

states it is not available to others because it includes certain modifications to account for 

system assumptions utilized in that market.276 PJM states that certain entities are 

 272 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 101. 

273 Financial Marketers Coalition Comments at 40-44; XO Energy Replacement 

Comments at 45-47.

274 ISO-NE Comments at 45-46; MISO Comments at 20.

275 NYISO Comments at 12-13; PJM Comments at 11-12.

276 NYISO Comments at 12-13.
Docket No. RM17-2-000 - 92 -

prohibited from accessing network models. PJM explains that in some instances it may 

share some of these models with certain entities, such as Transmission Owners, but only 

to coordinate the reliability of the transmission system with PJM, not for the sake of 

market transparency.277 

134. Some commenters argue against the wider dissemination of market models, noting

confidentiality concerns.

278 The PJM Market Monitor argues that there is no efficiency 

gain and potential market power issues could arise from the wider dissemination of 

market models.

279 Other commenters argue that market models should be available to all 

market participants,

280 or that releasing market models subject to CEII protection or nondisclosure agreements is appropriate.281 XO Energy, for example, asserts that access to 

market models would allow market participants to place transactions that increase market 

efficiency and reliability.

282 

 277 PJM Comments at 11-12.

278 MISO Transmission Owners Comments at 14-15; PJM Comments at 11-12.

279 PJM Market Monitor Comments at 11-12.

280 AWEA Comments at 10-14; Designated Marketers Comments at 7; TAPS 

Comments at 10; XO Energy Replacement Comments at 45-47.

281 Appian Way Comments at 8; Designated Marketers Comments at 7; ISO-NE 

Comments at 45-46; XO Energy Replacement Comments at 45-47.

282 XO Energy Reply Comments at 8.
Docket No. RM17-2-000 - 93 -

b. Determination

135. We appreciate the input from multiple commenters on the availability of market 

models. In the NOPR, the Commission sought comment on this topic but did not make a 

specific proposal. Accordingly, based on the record in this proceeding, we will not 

require changes to the accessibility of market models at this time. 

V. Compliance and Implementation Timelines

136. In the NOPR, the Commission proposed to require that each RTO/ISO submit a 

compliance filing within 90 days of the effective date of the Final Rule. The Commission 

also requested comment on whether 90 days provided sufficient time for RTOs/ISOs to 

develop new tariff language in response to the Final Rule. The Commission also 

proposed that tariff changes implementing the Final Rule must become effective no more 

than six months after compliance filings are due.283 

A. Comments

137. The Commission did not propose separate compliance and implementation 

deadlines for the uplift cost allocation and transparency reforms. Accordingly, most of 

the comments received on this subject understandably address compliance and 

implementation assuming that the Final Rule would address both proposed reforms. We 

do not discuss comments that solely addressed compliance and implementation of the 

proposed uplift cost allocation reform.

 283 NOPR, FERC Stats. & Regs. ¶ 32,721 at P 102.
Docket No. RM17-2-000 - 94 -

138. MISO requests that the Commission consider a compliance timeline of 120 days, 

citing a need to review existing protocols, refine current processes to reflect any changes 

stemming from the NOPR proposal, and discuss changes with stakeholders. MISO 

requests that the Commission consider an implementation timeline of 365 days, as MISO 

estimates that the coding and testing of new software will likely take a minimum of 

60 to 90 days.284

139. ISO-NE states that the 90-day compliance deadline is too short as it leaves 

insufficient time to consult with stakeholders, consider alternative compliance approaches 

and develop and file tariff changes. ISO-NE also asserts that the six-month deadline 

appears arbitrary. ISO-NE concludes that the Commission should allow RTOs/ISOs to 

submit a compliance proposal and schedule that reflects each region’s unique 

circumstances, which may vary significantly.285 However, ISO-NE’s support for its 

position focuses on the proposed uplift cost allocation reforms, which are not a part of 

this Final Rule. PJM supports the 90-day compliance deadline. PJM states specifically 

that it could implement the proposed transparency changes within nine months after 

issuance of a final rule.286 NYISO is silent on the compliance deadline, but states that it 

 284 MISO Comments at 20-21.

285 ISO-NE Comments at 46-47.

286 PJM Comments at 17.
Docket No. RM17-2-000 - 95 -

would require at least nine months for implementation.287 CAISO and SPP do not 

comment on compliance or implementation timelines. 

140. Direct Energy states that the shorter the period for implementing the changes to 

transparency requirements the better, as the changes will only enhance RTO/ISO 

markets.288 APPA and NRECA recommend that the Commission seek input from 

RTOs/ISOs regarding the feasibility and timing of their ability to comply with the 

transparency provisions.289

B. Determination

141. In the NOPR, the Commission did not propose separate compliance and 

implementation deadlines for the uplift cost allocation and transparency reforms. Most of 

the comments received on this subject address compliance and implementation assuming 

a Final Rule would address both initiatives, and in several cases, focused only on 

compliance and implementation related to the uplift cost allocation initiative. As this 

Final Rule only addresses the transparency initiative, we reason that some of the 

proposed compliance and implementation deadline concerns may be alleviated. We 

agree with Direct Energy that it is preferable that the transparency benefits of these 

reforms be realized as quickly as possible. Therefore, we require that each RTO/ISO 

submit a compliance filing within 60 days of the effective date of this Final Rule that 

 287 NYISO Comments at 13.

288 Direct Energy Comments at 11.

289 APPA and NRECA Comments at 2, 13.
Docket No. RM17-2-000 - 96 -

establishes in its tariff the three reporting requirements and one requirement related to 

transmission constraint penalty factors as described herein. Further, we require tariff 

changes to become effective no more than 120 days after compliance filings are due. 

VI. Information Collection Statement

142. The Paperwork Reduction Act (PRA)290 requires each federal agency to seek and 

obtain Office of Management and Budget (OMB) approval before undertaking a 

collection of information directed to ten or more persons or contained in a rule of general 

applicability. OMB’s regulations,291 in turn, require approval of certain information 

collection requirements imposed by agency rules. Upon approval of a collection(s) of 

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

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

to respond to these collection(s) of information unless the collection(s) of information 

display a valid OMB control number. 

143. In this Final Rule, we are amending the Commission’s regulations to improve the 

operation of organized wholesale electric power markets operated by RTOs/ISOs. We 

require that each RTO/ISO: (1) report, on a monthly basis, uplift payments for each 

transmission zone, broken out by day and uplift category (Zonal Uplift Report); 

(2) report, on a monthly basis, total uplift payments for each resource (Resource-Specific 

Uplift Report); (3) report, on a monthly basis, for each operator-initiated commitment,

 290 44 U.S.C. 3501-3520.

291 5 CFR 1320 (2017).
Docket No. RM17-2-000 - 97 -

the size of the commitment, transmission zone, commitment reason, and commitment 

start time (Operator-Initiated Commitment Report); and (4) define in its tariff the 

transmission constraint penalty factors, as well as the circumstances under which those 

factors can set locational marginal prices (LMP), and any process by which they can be 

changed (Transmission Constraint Penalty Factor Requirements). 

144. The reforms required in this Final Rule include a one-time tariff filing with the 

Commission due 60 days after the effective date of this Final Rule. The reforms will also 

require each RTO/ISO to maintain and post the three reports on an ongoing basis. We 

estimate this will require about 36 hours each year (three hours each month) for each 

RTO/ISO. We anticipate the reforms proposed in this Final Rule, once implemented,

would not significantly change currently existing burdens on an ongoing basis. The 

Commission will submit the proposed reporting requirements to OMB for its review and 

approval under section 3507(d) of the Paperwork Reduction Act.292

145. In the NOPR, the Commission requested comments on its need for this 

information, whether the information will have practical utility, the accuracy of burden 

and cost estimates, ways to enhance the quality, utility, and clarity of the information to 

be collected or retained, and any suggested methods for minimizing respondents’ burden, 

including the use of automated information techniques. The comments and the 

Commission’s determinations related to these issues are discussed above.

Burden Estimate and Information Collection Costs: The Commission believes that the 

 292 44 U.S.C. 3507(d).
Docket No. RM17-2-000 - 98 -

burden estimates below are representative of the average burden on respondents, 

including necessary communications with stakeholders. The estimated burden and 

cost293 for the requirements contained in this Final Rule follow.

294

FERC-516G, as implemented by the Final Rule in Docket RM17-2-000

Number of 

Respondents

295

(1)

Annual 

Number of 

Responses 

per 

Respondent

(2)

Total Number 

of Responses 

(1)×(2)=(3)

Average 

Burden 

Hours & 

Cost Per 

Response

(4)

Total 

Annual 

Burden 

Hours & 

Total 

Annual Cost

(3)×(4)=(5)

Cost per 

Respondent

($)

(5)÷(1)

One-Time 

Effort (in 

Year 1) to (a)

establish

process for 

reporting on 

company 

website,296

& (b) submit 

tariff filing 

6 1 6 500 hrs.; 

$38,500

3,000 hrs.; 

$231,000

$38,500

 293 The estimated hourly cost (salary plus benefits) provided in this section are 

based on the salary figures for May 2016 posted by the Bureau of Labor Statistics for the 

Utilities sector (available at http://www.bls.gov/oes/current/naics2_22.htm#00-0000) and 

benefits effective September 2017 (issued 12/15/2017, available at

http://www.bls.gov/news.release/ecec.nr0.htm). The hourly estimates for salary plus 

benefits are: (a) Legal (code 23-0000), $143.68; (b) Computer and Mathematical (code 

15-0000), $60.70; (c) Information Security Analyst (code 15-1122), $66.34; (d) 

Accountant and Auditor (code 13-2011), $53.00; (e) Information and Record Clerk (code 

43-4199), $39.14; (e) Electrical Engineer (code 17-2071), $68.12; (f) Economist (code 

19-3011), $77.96; (g) Computer and Information Systems Manager (code 11-3021), 

$100.68; (h) Management (code 11-0000), $81.52. The average hourly cost (salary plus 

benefits), weighting all of these skill sets equally, is $76.79. For these calculations, we 

round that figure to $77 per hour.

294 The RTOs/ISOs (CAISO, SPP, MISO, PJM, NYISO, and ISO-NE) are required 

to comply with the reforms in this Final Rule. 

295 Respondent entities are either RTOs or ISOs.

296 This includes monthly reporting/posting on the company website for: (1) the 

Zonal Uplift Report (posting within 20 days of end of month), (2) the Resource-Specific 
Docket No. RM17-2-000 - 99 -

Ongoing 

Preparing and 

Posting of 3 

reports on 

company 

website each 

month

(starting in 

Year 1), as 

mentioned 

above

6 12 72 3 hrs.; $231 216 hrs.; 

$16,632 

$2,772

Cost to Comply: The Commission has projected the total cost of compliance to industry 

to be: one-time in Year 1, $231,000; and ongoing, starting in Year 1, $16,632.

Title: FERC-516G, Electric Rate Schedules and Tariff Filings in Docket RM17-2-000.

Action: New information collection.

OMB Control No.: 1902-0295.

Respondents for this Rulemaking: RTOs/ISOs.

Frequency of Information: One-time, and ongoing posting to company website.

Necessity of Information: The Federal Energy Regulatory Commission implements this 

rule to improve competitive wholesale electric markets in the RTO/ISO regions. 

Internal Review: The Commission has reviewed the changes and has determined that 

such changes are necessary. These requirements conform to the Commission’s need for 

efficient information collection, communication, and management within the energy 

industry. The Commission has specific, objective support for the burden estimates 

 

Uplift Report (posting within 90 days of end of month), and (3) the Operator-Initiated 

Commitments Report (posting within 30 days of the end of month).
Docket No. RM17-2-000 - 100 -

associated with the information collection requirements.

Interested persons may obtain information on the reporting requirements by contacting 

the following: Federal Energy Regulatory Commission, 888 First Street, NE, 

Washington, 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 collection of information and the associated burden estimate(s) 

may also be sent to the Office of Information and Regulatory Affairs, 

Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503 

[Attention: Desk Officer for the Federal Energy Regulatory Commission]. Due to 

security concerns, comments should be sent electronically to the following e-mail 

address: oira_submission@omb.eop.gov. Comments submitted to OMB should refer to 

FERC-516G and OMB Control No. 1902-0295.

VII. Environmental Analysis

146. 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.297 The Commission concludes that neither an Environmental

Assessment nor an Environmental Impact Statement is required for this Final Rule under 

section 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the Federal Power Act 

 297 Regulations Implementing the National Environmental Policy Act, Order 

No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987).
Docket No. RM17-2-000 - 101 -

relating to the filing of schedules containing all rates and charges for the transmission or 

sale of electric energy subject to the Commission’s jurisdiction, plus the classification, 

practices, contracts and regulations that affect rates, charges, classifications, and 

services.298

VIII. Regulatory Flexibility Act

147. The Regulatory Flexibility Act of 1980 (RFA)299 generally requires a description 

and analysis of final rules that will have significant economic impact on a substantial 

number of small entities. The RFA does not mandate any particular outcome in a 

rulemaking. It only requires consideration of alternatives that are less burdensome to 

small entities and an agency explanation of why alternatives were rejected.

148. This rule would apply to six RTOs/ISOs (all of which are transmission 

organizations). The average estimated annual PRA-related cost to each of the 

RTOs/ISOs is $41,272 (one-time and ongoing costs) in Year 1, and $2,772 (ongoing cost) 

in Year 2 and beyond. This cost of implementing these changes is not significant. 

Additionally, the RTOs/ISOs are not small entities, as defined by the RFA.300 This is 

 298 18 CFR 380.4(a)(15) (2017). 

299 5 U.S.C. 601-612.

300 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act, which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. The 

Small Business Administrations’ regulations at 13 CFR 121.201 define the threshold for 

a small Electric Bulk Power Transmission and Control entity (NAICS code 221121) to be 

500 employees. See 5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 

15 U.S.C. 632.
Docket No. RM17-2-000 - 102 -

because the relevant threshold between small and large entities is 500 employees and the 

Commission understands that each RTO/ISO has more than 500 employees. 

Furthermore, because of their pivotal roles in wholesale electric power markets in their 

regions, none of the RTOs/ISOs meet the last criterion of the two-part RFA definition a 

small entity: “not dominant in its field of operation.” As a result, we certify that this 

Final Rule would not have a significant economic impact on a substantial number of 

small entities. 

IX. Document Availability

149. 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 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, NE, Room 2A, 

Washington DC 20426.

150. 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.

151. 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) 
Docket No. RM17-2-000 - 103 -

502-8371, TTY (202) 502-8659. E-mail the Public Reference Room 

at public.referenceroom@ferc.gov.

X. Effective Date and Congressional Notification

152. These regulations are effective [insert date 75 days from publication in Federal 

Register]. The Commission has determined, with the concurrence of the Administrator of 

the Office of Information and Regulatory Affairs of OMB, that this rule is not a “major 

rule” as defined in section 251 of the Small Business Regulatory Enforcement Fairness 

Act of 1996. The Final Rule will be provided to both Houses of Congress, the 

Government Accountability Office, and the Small Business Administration.
Docket No. RM17-2-000 - 104 -

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. RM17-2-000 - 105 -

Regulatory Text

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 § 35.28 as follows:

a. Add a new paragraph (g)(10)(i).

b. Add a new paragraph (g)(10)(ii).

c. Add a new paragraph (g)(10)(iii).

The revisions and addition read as follows:

§ 35.28 Non-discriminatory open access transmission tariff.

* * * * *

(g) Tariffs and operations of Commission-approved independent system 

operators and regional transmission organizations. * * *

(10) Transparency

(i) Uplift reporting. Each Commission-approved independent

system operator or regional transmission organization must post two reports, at 

minimum, regarding uplift on a publicly accessible portion of its website. First, each 

Commission-approved independent system operator or regional transmission 
Docket No. RM17-2-000 - 106 -

organization must post uplift, paid in dollars, and categorized by transmission zone, day, 

and uplift category. Transmission zone shall be defined as the geographic area that is 

used for the local allocation of charges. Transmission zones with fewer than four 

resources may be aggregated with one or more neighboring transmission zones, until 

each aggregated zone contains at least four resources, and reported collectively. This 

report shall be posted within 20 calendar days of the end of each month. Second, each 

Commission-approved independent system operator or regional transmission 

organization must post the resource name and the total amount of uplift paid in dollars 

aggregated across the month to each resource that received uplift payments within the 

calendar month. This report shall be posted within 90 calendar days of the end of each 

month.

(ii) Reporting Operator-Initiated Commitments. Each Commissionapproved independent system operator or regional transmission organization must post a

report of each operator-initiated commitment listing the size of the commitment, 

transmission zone, commitment reason, and commitment start time on a publicly 

accessible portion of its website within 30 calendar days of the end of each month. 

Transmission zone shall be defined as a geographic area that is used for the local 

allocation of charges. Commitment reasons shall include, but are not limited to, systemwide capacity, constraint management, and voltage support.

(iii) Transmission constraint penalty factors. Each Commissionapproved independent system operator or regional transmission organization must 

include, in its tariff, its transmission constraint penalty factor values; the circumstances, if 
Docket No. RM17-2-000 - 107 -

any, under which the transmission constraint penalty factors can set locational marginal 

prices; and the procedure, if any, for temporarily changing the transmission constraint 

penalty factor values. Any procedure for temporarily changing transmission constraint 

penalty factor values must provide for notice of the change to market participants.
Docket No. RM17-2-000 - 108 -

The following appendix will not appear in the Code of Federal Regulations.

APPENDIX: List of Short Names/Acronyms of Commenters 

Short Name/Acronym Commenter

APPA/NRECA American Public Power Association

and National Rural Electric 

Cooperative Association

Appian Way Appian Way Energy Partners, LLC

AWEA American Wind Energy Association

Brookfield Brookfield Energy Marketing LP

CAISO California Independent System 

Operator Corporation

CAISO Market Monitor Department of Market Monitoring for 

the California Independent System 

Operator Corporation

California SWP California Department of Water 

Resources State Water Project

Calpine Calpine Energy Solutions, LLC

Competitive Suppliers Electric Power Supply Association;

PJM Power Providers; and Western 

Power Trading Forum

Direct Energy Direct Energy Business, LLC, on 

behalf of itself and its affiliate, Direct 

Energy Business Marketing, LLC

Diversified Trading/eXion Energy Diversified Trading Company, LLC 

and eXion Energy, Inc.

EDF EDF Renewable Energy, Inc.

EEI Edison Electric Institute

ELCON Electricity Consumers Resource 

Council

Exelon Exelon Corporation

Financial Marketers Coalition Financial Marketers Coalition

Golden Spread Golden Spread Electric Cooperative, 

Inc.
Docket No. RM17-2-000 - 109 -

ISO-NE ISO New England, Inc.

IRC ISO/RTO Council 

Joint Marketers DC Energy, LLC; Mercuria Energy 

Trading, Inc.; and Perdisco Trading, 

LLC

MISO Midcontinent Independent System 

Operator, Inc.

MISO Transmission Owners Ameren Services Company, as agent 

for Union Electric Company d/b/a 

Ameren Missouri, Ameren Illinois 

Company d/b/a Ameren Illinois and 

Ameren Transmission Company of 

Illinois; Big Rivers Electric 

Corporation; Central Minnesota 

Municipal Power Agency; City Water, 

Light & Power (Springfield, IL); Cleco 

Power LLC; Cooperative Energy; 

Dairyland Power Cooperative; Duke 

Energy Business Services, LLC for 

Duke Energy Indiana, LLC; East 

Texas Electric Cooperative; Entergy 

Arkansas, Inc.; Entergy Louisiana, 

LLC; Entergy Mississippi, Inc.; 

Entergy New Orleans, Inc.; Entergy 

Texas, Inc.; Great River Energy; 

Hoosier Energy Rural Electric 

Cooperative, Inc.; Indiana Municipal 

Power Agency; Indianapolis Power & 

Light Company; MidAmerican Energy 

Company; Minnesota Power (and its 

subsidiary Superior Water, L&P); 

Missouri River Energy Services; 

Montana-Dakota Utilities Co.; 

Northern Indiana Public Service 

Company; Northern States Power 

Company, a Minnesota corporation, 

and Northern States Power Company, 

a Wisconsin corporation, subsidiaries 

of Xcel Energy Inc.; Northwestern 

Wisconsin Electric Company; Otter 

Tail Power Company; Prairie Power 

Inc.; Southern Illinois Power 
Docket No. RM17-2-000 - 110 -

Cooperative; Southern Indiana Gas & 

Electric Company (d/b/a Vectren 

Energy Delivery of Indiana); Southern 

Minnesota Municipal Power Agency; 

Wabash Valley Power Association, 

Inc.; and Wolverine Power Supply 

Cooperative, Inc.

NCPA Northern California Power Agency

NYISO New York Independent System 

Operator, Inc.

PG&E Pacific Gas and Electric Company

PJM PJM Interconnection, L.L.C. 

PJM Market Monitor Monitoring Analytics, LLC, acting in 

its capacity as the Independent Market 

Monitor for PJM

Potomac Economics Potomac Economics, Ltd.

R Street Institute R Street Institute

Six Cities Cities of Anaheim, Azusa, Banning, 

Colton, Pasadena, and Riverside,

California

SPP Southwest Power Pool, Inc.

SPP Market Monitor Southwest Power Pool, Inc. Market 

Monitoring Unit

TAPS Transmission Access Policy Study 

Group

XO Energy XO Energy, LLC