Uplift Cost Allocation and Transparency in Markets Operated by Regional Transmission Organizations and Independent System Operators, 18134-18157 [2018-08609]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 83, Number 80 (Wednesday, April 25, 2018)]
[Rules and Regulations]
[Pages 18134-18157]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-08609]



[[Page 18133]]

Vol. 83

Wednesday,

No. 80

April 25, 2018

Part II





Department of Energy





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Federal Energy Regulatory Commission





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18 CFR Part 35





Uplift Cost Allocation and Transparency in Markets Operated by Regional 
Transmission Organizations and Independent System Operators; Final Rule

Federal Register / Vol. 83, No. 80 / Wednesday, April 25, 2018 / 
Rules and Regulations

[[Page 18134]]


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DEPARTMENT OF ENERGY

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

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

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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 to have caused the real-time 
uplift costs.

DATES: This rule is effective July 9, 2018.

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, [email protected].
Katherine Scott (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE, 
Washington, DC 20426, (202) 502-6495, [email protected].
Colin Beckman (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE, Washington, 
DC 20426, (202) 502-8049, [email protected]

SUPPLEMENTARY INFORMATION: 
Before Commissioners: Kevin J. McIntyre, Chairman; Cheryl A. 
LaFleur, Neil Chatterjee, Robert F. Powelson, and Richard Glick.

                            Table of Contents
 
                                                         Paragraph Nos.
 
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
        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.
 


[[Page 18135]]

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 
factors \2\ 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 (LMP), and any process by which they can be changed 
(Transmission Constraint Penalty Factor Requirements).
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    \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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    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 cost-effective 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.
    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.
    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.
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    \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).
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    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 constraints of reliably operating the 
system; and (4) ensure that all suppliers have an opportunity to 
recover their costs.\5\
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    \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).
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    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

[[Page 18136]]

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 
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 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.
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    \6\ Order Directing Reports, 153 FERC ] 61,221.
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    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\
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    \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.
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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.
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    \9\ NOPR, FERC Stats. & Regs. ] 32,721 at PP 59-66.
    \10\ Order Directing Reports, 153 FERC ] 61,221.
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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 Guarantee \13\ 
Report eight days 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\
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    \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).
    \14\ MISO Comments at 11-12.
    \15\ See CAISO, Monthly Market Performance Report, https://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=A9180EE4-8972-4F3B-9CB8-21D0809B645E. 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).
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    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\
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    \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).
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    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

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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\
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    \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.
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    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 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 dispatches \23\ (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\
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    \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, https://www.caiso.com/market/Pages/DailyExceptionalDispatch/Default.aspx.
    \25\ NYISO Comments at 8 & n.29; NYISO Report at 56-57 and n.32.
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    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., day-ahead 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\
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    \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.
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    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 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.
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    \31\ PJM Report at 49-50.
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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 
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\
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    \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).
    \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.
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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 stakeholder process. The Commission posed, as an 
example, the scenario of releasing information about

[[Page 18138]]

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\
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    \35\ NOPR, FERC Stats. & Regs. ] 32,721 at PP 77-79.
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    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\
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    \36\ Id. P 80.
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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 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 Marketers Coalition state that 
transparency is critical to a well-functioning organized market because 
it is the key to proper price signals.\43\
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    \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.
    \43\ Financial Marketers Coalition Comments at 36-37.
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    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 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\
---------------------------------------------------------------------------

    \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.
    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \50\ CAISO Comments at 2-3.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

[[Page 18139]]

commitments are 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 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 real-time 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.
---------------------------------------------------------------------------

    \54\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    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. 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 machine-readable 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.
    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\
---------------------------------------------------------------------------

    \55\ NOPR, FERC Stats. & Regs, ] 32,721 at Regulatory Text.
---------------------------------------------------------------------------

    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 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-

[[Page 18140]]

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\
---------------------------------------------------------------------------

    \56\ Id. P 84.
    \57\ Id. PP 87-89.
    \58\ Id. P 88.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \59\ Id. P 85.
    \60\ Id. P 86.
    \61\ Id. P 86.
---------------------------------------------------------------------------

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 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\
---------------------------------------------------------------------------

    \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.
    \66\ Competitive Suppliers Comments at 9.
    \67\ Id. at 9; Financial Marketers Coalition Comments at 38.
---------------------------------------------------------------------------

    40. Other commenters either do not support the proposed zonal 
uplift report requirement \68\ 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.
---------------------------------------------------------------------------

    \68\ CAISO Comments at 12-13.
    \69\ EEI Comments at 6; MISO Transmission Owners Comments at 5-
6; NYISO Comments at 5.
---------------------------------------------------------------------------

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 
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\
---------------------------------------------------------------------------

    \70\ NOPR, FERC Stats. & Regs. ] 32,721 at P 85.
    \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.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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

[[Page 18141]]

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 
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\
---------------------------------------------------------------------------

    \80\ NOPR, FERC Stats. & Regs. ] 32,721 at P 89.
    \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.
    \86\ EEI Comments at 8.
---------------------------------------------------------------------------

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 
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-of-merit 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\
---------------------------------------------------------------------------

    \87\ NYISO Comments at 6.
    \88\ MISO Comments at 11.
    \89\ ISO-NE Comments at 42.
    \90\ PJM Comments at 12.
    \91\ Brookfield Comments at 2.
    \92\ XO Energy Replacement Comments at 34.
---------------------------------------------------------------------------

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 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\
---------------------------------------------------------------------------

    \93\ ISO-NE Comments at 43.
    \94\ NYISO Comments at 5-6.
    \95\ MISO Comments at 11.
    \96\ Calpine Comments at 8; PJM Comments at 13.
    \97\ CAISO Comments at 12-13.
---------------------------------------------------------------------------

    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 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 time-consuming to produce 
quickly, RTOs/ISOs should post a simple spreadsheet on their website 
while their systems are being updated.\100\
---------------------------------------------------------------------------

    \98\ XO Energy Reply Comments at A-2.
    \99\ XO Energy Replacement Comments at 34; XO Energy Reply 
Comments at A-3.
    \100\ XO Energy Replacement Comments at 34.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \101\ Direct Energy Comments at 10.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \102\ EEI Comments at 7; MISO Transmission Owners Comments at 
13.
    \103\ Designated Marketers Comments at 8.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \104\ Exelon Comments at 9-10.
---------------------------------------------------------------------------

3. Determination
    50. We adopt the proposal that each RTO/ISO report, in the Zonal 
Uplift Report, the total daily uplift payments

[[Page 18142]]

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 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.
---------------------------------------------------------------------------

    \105\ NOPR, FERC Stats. & Regs. ] 32,721 at PP 78, 84.
    \106\ PJM, PJM Cold Snap Performance, Dec. 28, 2017 to Jan. 7, 
2018, 27-30 (Feb. 26, 2018), https://www.pjm.com/-/media/library/reports-notices/weather-related/20180226-january-2018-cold-weather-event-report.ashx (PJM Cold Snap Performance Report).
---------------------------------------------------------------------------

    51. We address commenters' concerns regarding the Zonal Uplift 
Report below.
    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 Resource-Specific 
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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 Resource-Specific Uplift Report \108\ 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \109\ PJM Comments at 12; PJM Market Monitor Comments at 10.
---------------------------------------------------------------------------

    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 with 
four units, aggregation with a neighboring

[[Page 18143]]

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 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.
---------------------------------------------------------------------------

    \110\ NOPR, FERC Stats. & Regs. ] 32,721 at P 86.
---------------------------------------------------------------------------

    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 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.

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\
---------------------------------------------------------------------------

    \111\ Id. at Regulatory Text.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \112\ Id. P 84.
    \113\ Id. P 89.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \114\ Id. P 83.
    \115\ Id. P 86.
---------------------------------------------------------------------------

2. Comments
    66. Many commenters generally support \116\ or state that they are 
not opposed \117\ 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

[[Page 18144]]

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 through 
competition.\121\ Similarly, XO Energy agrees that the usefulness of 
data will be reduced if it is aggregated.\122\
---------------------------------------------------------------------------

    \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.
    \121\ Financial Marketers Coalition Comments at 38.
    \122\ XO Energy Replacement Comments at 34.
---------------------------------------------------------------------------

    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 resource-specific 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 considered confidential in their regions.\132\ PJM does not oppose 
the NOPR proposal, but notes stakeholder concerns that resource-
specific uplift reporting could reveal market-sensitive information 
such as bidding strategies.\133\ The SPP Market Monitor contends that 
identifiable information for resources should not be released.\134\
---------------------------------------------------------------------------

    \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.
    \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.
---------------------------------------------------------------------------

    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 Commission allow RTOs/ISOs 
to determine the level of transparency needed to protect commercially 
sensitive information.\139\
---------------------------------------------------------------------------

    \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.
    \139\ EEI Comments at 8-9.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \140\ Potomac Economics Comments at 11.
    \141\ MISO Transmission Owners Comments at 10-11.
    \142\ EEI Comments at 8.
---------------------------------------------------------------------------

    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

[[Page 18145]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 implement.\153\
---------------------------------------------------------------------------

    \152\ CAISO Comments at 12.
    \153\ ISO-NE Comments at 43.
---------------------------------------------------------------------------

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 
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 units \155\ 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.
---------------------------------------------------------------------------

    \154\ Staff Analysis of Uplift at 7-10.
    \155\ PJM Cold Snap Performance Report at 30.
---------------------------------------------------------------------------

    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 
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 Resource-Specific 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 
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

[[Page 18146]]

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 resource-specific 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 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 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\
---------------------------------------------------------------------------

    \158\ NOPR, FERC Stats. & Regs. ] 32,721 at Regulatory Text.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \159\ Id. P 92.
---------------------------------------------------------------------------

    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 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 whether 
more information is needed (e.g., specific constraint name), as well as 
any potential concerns with requiring additional information.\164\
---------------------------------------------------------------------------

    \160\ Id. P 93.
    \161\ Id. P 90.
    \162\ Id. P 91.
    \163\ Id. P 94.
    \164\ Id. P 95.
---------------------------------------------------------------------------

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

[[Page 18147]]

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 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.
---------------------------------------------------------------------------

    \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.
    \167\ Financial Marketers Coalition Comments at 37.
    \168\ Id.
    \169\ R Street Institute Comments at 5-6.
---------------------------------------------------------------------------

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 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 operator-initiated 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\
---------------------------------------------------------------------------

    \170\ NYISO Comments at 8-11.
    \171\ MISO Comments at 14-15 (citing NOPR, FERC Stats. & Regs. ] 
32,721 at P 90).
---------------------------------------------------------------------------

    89. PJM states that it does not have any automated commitments in 
either the real-time or day-ahead market; instead PJM has a variety of 
applications that provide 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\
---------------------------------------------------------------------------

    \172\ PJM Comments at 13-14.
---------------------------------------------------------------------------

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 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\
---------------------------------------------------------------------------

    \173\ ISO-NE Comments at 44; MISO Comments at 18; SPP Comments 
at 3-4.
    \174\ MISO Comments at 18.
    \175\ Id. at 17.
    \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.
---------------------------------------------------------------------------

    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 should 
be as granularly specific as possible.\182\ XO Energy points to MISO's 
operator-initiated 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\
---------------------------------------------------------------------------

    \181\ XO Energy Reply Comments at A-9.
    \182\ XO Energy Replacement Comments at 34-35.
    \183\ Id. at 35.
    \184\ EEI Comments at 9.
---------------------------------------------------------------------------

    92. ISO-NE and PJM raise concerns that the proposed operator-
initiated commitment reports could reveal Critical Energy/Electric 
Infrastructure Information (CEII).\185\ ISO-NE states

[[Page 18148]]

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 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\
---------------------------------------------------------------------------

    \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 FR 93732 (Dec. 21, 2016), FERC Stats. & Regs. ] 31,389 
(2016).
    \186\ ISO-NE Comments at 44.
    \187\ PJM Comments at 14.
    \188\ XO Energy Reply Comments at A-7.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \192\ EEI Comments at 9; PJM Comments at 14.
    \193\ EEI Comments at 9.
    \194\ MISO Comments at 15-16.
    \195\ PJM Comments at 14.
---------------------------------------------------------------------------

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 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\
---------------------------------------------------------------------------

    \196\ NOPR, FERC Stats. & Regs. ] 32,721 at P 94.
    \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.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \201\ CAISO Comments at 14.
    \202\ Id. at 14-15.
---------------------------------------------------------------------------

    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, 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

[[Page 18149]]

reasonable and already met by NYISO, MISO, and CAISO.\207\
---------------------------------------------------------------------------

    \203\ XO Energy Reply Comments at A-3.
    \204\ Id. at A-3.
    \205\ Id. at A-1.
    \206\ Competitive Suppliers Comments at 12.
    \207\ R Street Institute Comments at 5-6.
---------------------------------------------------------------------------

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 uplift, such as load biasing. 
Furthermore, Competitive Suppliers argue that self-scheduled 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\
---------------------------------------------------------------------------

    \208\ XO Energy Replacement Comments at 35.
    \209\ Competitive Suppliers Comments at 10-11.
    \210\ Golden Spread Comments at 12-13.
    \211\ EEI Comments at 9-10.
---------------------------------------------------------------------------

3. Determination
    99. We adopt the NOPR proposal and require each RTO/ISO to post all 
operator-initiated 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 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.
---------------------------------------------------------------------------

    \212\ NOPR, FERC Stats. & Regs. ] 32,721 at PP 92-93.
---------------------------------------------------------------------------

    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 the definition of an operator-initiated commitment to 
be a commitment after the day-ahead 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 look-ahead 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.
---------------------------------------------------------------------------

    \213\ Id. P 90.
---------------------------------------------------------------------------

    101. PJM requests clarification that we intend to require PJM to 
report all commitments 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 real-time, 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

[[Page 18150]]

near-real-time reporting of operator-initiated commitments, we instead 
will 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.
---------------------------------------------------------------------------

    \214\ Id. P 94.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \215\ Id. P 91.
---------------------------------------------------------------------------

    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 
commercially-sensitive information. As discussed above, RTOs/ISOs may 
have multiple existing types 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 commitment reasons listed in the 
NOPR \216\ 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: system-wide 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.
---------------------------------------------------------------------------

    \216\ Id. P 95 and n.109.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \217\ 16 U.S.C. 824d.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \218\ NOPR, FERC Stats. & Regs. ] 32,721 at Regulatory Text.
---------------------------------------------------------------------------

    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, market participants may not be able to hedge transactions 
appropriately or raise concerns into RTO/ISO practices through the 
stakeholder process.\219\
---------------------------------------------------------------------------

    \219\ Id. P 80.
---------------------------------------------------------------------------

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

[[Page 18151]]

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 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.
---------------------------------------------------------------------------

    \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.
    \223\ Financial Marketers Coalition Comments at 45; MISO 
Comments at 18.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \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).
    \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), https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2015/2015-som-pjm-volume2-sec3.pdf).
    \230\ ISO-NE Comments at 44-45.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \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.
    \233\ Potomac Economics Comments at 14-15.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \234\ R Street Institute Comments at 6.
    \235\ XO Energy Comments at 38.
    \236\ Id. at 37.
    \237\ Financial Marketers Coalition Comments at 45.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \238\ Potomac Economics Comments at 16.
    \239\ PJM Market Monitor Comments at 11.
---------------------------------------------------------------------------

    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 commitments, dispatch levels, and 
reliability, and therefore RTOs/ISOs should file any provisions to 
adjust them.\242\
---------------------------------------------------------------------------

    \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.
    \242\ Id. at 13-14.
---------------------------------------------------------------------------

    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

[[Page 18152]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \247\ XO Energy Replacement Comments at 43.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \248\ Potomac Economics Comments at 14.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \249\ XO Energy Replacement Comments at 36, 39 (citing PJM, 
Transmission Constraint Control Logic in Market Clearing Engines 
(March 2017), https://www.pjm.com/~/media/committees-groups/
committees/mic/20170308/20170308-informational-only-transmission-
constraint-control-logic-in-mces.ashx).
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \254\ NOPR, FERC Stats. & Regs. ] 32,721 at P 98.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \255\ MISO Comments at 19.
    \256\ ISO-NE Comments at 45.
    \257\ NYISO Comments at 12.
    \258\ PJM Comments at 15.
---------------------------------------------------------------------------

    125. Several commenters support additional transparency into 
transmission outages.\259\ 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

[[Page 18153]]

efficiency and reduce uncertainty for participants.\261\
---------------------------------------------------------------------------

    \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 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \262\ XO Energy Replacement Comments at 43-44.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \263\ Diversified Trading/eXion Energy Comments at 5-7; XO 
Energy Replacement Comments at 44-45.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \264\ EDF Comments at 1.
    \265\ Id. at 5.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \266\ MISO Comments at 19; PJM Comments at 12.
    \267\ MISO Transmission Owners Comments at 15.
    \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.
---------------------------------------------------------------------------

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 ``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\
---------------------------------------------------------------------------

    \272\ NOPR, FERC Stats. & Regs. ] 32,721 at P 101.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \273\ Financial Marketers Coalition Comments at 40-44; XO Energy 
Replacement Comments at 45-47.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \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.
    \277\ PJM Comments at 11-12.
---------------------------------------------------------------------------

    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 non-disclosure 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

[[Page 18154]]

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\
---------------------------------------------------------------------------

    \283\ NOPR, FERC Stats. & Regs. ] 32,721 at P 102.
---------------------------------------------------------------------------

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.
    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\
---------------------------------------------------------------------------

    \284\ MISO Comments at 20-21.
---------------------------------------------------------------------------

    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 would require at least nine months for 
implementation.\287\ CAISO and SPP do not comment on compliance or 
implementation timelines.
---------------------------------------------------------------------------

    \285\ ISO-NE Comments at 46-47.
    \286\ PJM Comments at 17.
    \287\ NYISO Comments at 13.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \288\ Direct Energy Comments at 11.
    \289\ APPA and NRECA Comments at 2, 13.
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \290\ 44 U.S.C. 3501-3520.
    \291\ 5 CFR 1320 (2017).
---------------------------------------------------------------------------

    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, 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\
---------------------------------------------------------------------------

    \292\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    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.

[[Page 18155]]

    Burden Estimate and Information Collection Costs: The Commission 
believes that the burden estimates below are representative of the 
average burden on respondents, including necessary communications with 
stakeholders. The estimated burden and cost \293\ for the requirements 
contained in this Final Rule follow.\294\
---------------------------------------------------------------------------

    \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 https://www.bls.gov/oes/current/naics2_22.htm#00-0000) 
and benefits effective September 2017 (issued 12/15/2017, available 
at https://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.

                                            FERC-516G, as Implemented by the Final Rule in Docket RM17-2-000
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                           Number of      Annual  number                                              Total annual burden      Cost per
                                          respondents      of  responses    Total number    Average  burden hours   hours and total  annual   respondent
                                             \295\        per  respondent   of responses    and cost per  response            cost               ($)
                                                    (1)               (2)     (1) x (2) =  (4)....................  (3) x (4) = (5)........    (5) / (1)
                                                                                      (3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
One-Time Effort (in Year 1) to (a)                    6                 1               6  500 hrs.; $38,500......  3,000 hrs.; $231,000...      $38,500
 establish process for reporting on
 company website,\296\ & (b) submit
 tariff filing.
Ongoing Preparing and Posting of 3                    6                12              72  3 hrs.; $231...........  216 hrs.; $16,632......        2,772
 reports on company website each
 month (starting in Year 1), as
 mentioned above.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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 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).
---------------------------------------------------------------------------

    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 
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], email: 
[email protected], 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 email address: 
[email protected]. 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 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\
---------------------------------------------------------------------------

    \297\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 
] 30,783 (1987).
    \298\ 18 CFR 380.4(a)(15) (2017).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \299\ 5 U.S.C. 601-612.
---------------------------------------------------------------------------

    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 
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.

[[Page 18156]]

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.
---------------------------------------------------------------------------

    \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.
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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 (https://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 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
[email protected].

X. Effective Date and Congressional Notification

    152. These regulations are effective July 9, 2018. 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.

List of Subjects in 18 CFR Part 35

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

    By the Commission.

    Issued: April 19, 2018.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

Regulatory Text

    In consideration of the foregoing, the Commission amends part 35, 
chapter I, title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
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.

0
2. Amend Sec.  35.28 by adding paragraph (g)(10) to read as follows:


Sec.  35.28   Non-discriminatory open access transmission tariff.

* * * * *
    (g) * * *
    (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 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 Commission-
approved 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, system-wide capacity, constraint management, 
and voltage support.
    (iii) Transmission constraint penalty factors. Each Commission-
approved independent system operator or regional transmission 
organization must include, in its tariff, its transmission constraint 
penalty factor values; the circumstances, if 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.

    Note: 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.

[[Page 18157]]

 
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.
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
                                        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.
------------------------------------------------------------------------


[FR Doc. 2018-08609 Filed 4-24-18; 8:45 am]
 BILLING CODE 6717-01-P